Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

This annual report on Form 10-K contains "forward-looking statements." All statements, other than statements of historical facts, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as future capital expenditures, business strategy, regulatory actions, and development, construction or operation of facilities (often, but not always, identified through the use of words or phrases such as "will likely result," "are expected to," "will continue," "is anticipated," "estimated," "projection," "target" and "outlook") are forward-looking statements.

Any forward-looking statement speaks only as of the date of this annual report, and, except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 retail electric distribution cooperative members. Our principal business is providing wholesale electric power to our members. As with cooperatives generally, we operate on a not-for-profit basis. We are one of the largest electric cooperatives in the United States in terms of revenues, assets, kilowatt-hour sales to members and, through our members, consumers served. We are also the second largest power supplier in the state of Georgia. We have ~~299~~337 employees.

Our members are local consumer-owned distribution cooperatives that provide retail electric service on a not-for-profit basis. In general, our members' customer base consists of residential, commercial and industrial consumers within specific geographic areas. Our members serve approximately ~~2.0~~2.1 million electric consumers (meters) representing approximately ~~4.3~~4.5 million people. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES."

Cooperatives like Oglethorpe are business organizations owned by their members, which are also either their wholesale or retail customers. As not-for-profit organizations, cooperatives are intended to provide services to their members at the lowest possible cost, in part by eliminating the need to produce profits or a return on equity. Cooperatives may make sales to non-members, the effect of which is generally to reduce costs to members. Today, cooperatives operate throughout the United States in such diverse areas as utilities, agriculture, irrigation, insurance and banking.

All cooperatives are based on similar business principles and legal foundations. Generally, an electric cooperative designs its rates to recover its cost-of-service and to collect a reasonable amount of revenues in excess of expenses, which constitutes margins. The margins increase patronage capital, which is the equity component of a cooperative's capitalization. These margins are considered capital contributions (that is, equity) from the members and are held for the accounts of the members and returned to them when the board of directors of the cooperative deems it prudent to do so. The timing and amount of any actual return of capital to the members depends on the financial goals of the cooperative and the cooperative's loan and security agreements. ~~See "– First Mortgage Indenture."~~

We provide wholesale electric service to our members for ~~more than half~~a significant portion of their aggregate power requirements primarily from our fleet of generation assets but also with power purchased from other power ~~suppliers.~~suppliers from time to time. In 2023, we supplied energy that accounted for approximately 68% of the retail energy requirements of our members. We provide this service pursuant to long-term, take-or-pay wholesale power contracts. The wholesale power contracts obligate our members jointly and severally to pay rates sufficient for us to recover all the costs of owning and operating our power supply business, including the payment of principal and interest on our indebtedness and to yield a minimum 1.10 margins for interest ratio under our first mortgage indenture. Our members satisfy all of their power requirements above their purchase obligations to us with purchases from other suppliers. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."

~~Our~~As of December 31, 2023, our fleet of generating units total ~~7,862~~8,525 megawatts of summer planning reserve capacity, which includes ~~737~~733 megawatts of Smarr EMC assets that we manage but do not own. Our generation portfolio includes units powered by nuclear, gas, coal, oil and water. We also supply financial and management services to support Green Power EMC's purchase of energy from ~~320~~756 megawatts of renewable resources, including, low-impact hydroelectric, landfill gas, wood-waste biomass and solar facilities. See "– Relationship with Green Power EMC," "OUR POWER SUPPLY

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~~The~~We have a wholesale power ~~contracts we have~~contract with each member ~~are~~that is substantially ~~similar~~similar. On November 15, 2023, we and ~~extend through~~each of our members extended the term of the contracts from December 31, 2050 to December 31, 2085, and each contract will continue thereafter until terminated by three years' written notice by us or the respective member. Under the wholesale power contracts, each member is unconditionally obligated, on an express "take-or-pay" basis, for a fixed percentage of the capacity costs of each of our generation resources and purchased power resources with a term greater than one year. Each wholesale power contract specifically provides that the member must make payments whether or not power is delivered and whether or not a resource is completed, delayed, terminated, operable, operating, retired, sold, leased, transferred or is otherwise unavailable. We are obligated to use our reasonable best efforts to operate, maintain and manage our resources in accordance with prudent utility practices.

We have assigned fixed percentage capacity cost responsibilities to our members for all of our generation ~~and purchased power~~ resources, although not all members participate in all resources. For any future generation or purchased power resource, we will assign fixed percentage capacity cost responsibilities only to members choosing to participate in that resource. The wholesale power contracts provide that each member is jointly and severally responsible for all costs and expenses of all existing generation and purchased power resources, as well as for future resources, whether or not that member has elected to participate in the resource, that are approved by 75% of the members of our board of directors, 75% of our members and members representing 75% of our patronage capital. In the event a member defaults on all or a portion of its payment obligation, the default amount is shared first among the participating members in each resource in which the defaulting member participates. If all these participating members default, each non-participating member is expressly obligated to pay a proportionate share of the default.

Under the wholesale power contracts, we are not obligated to provide all of our members' capacity and energy requirements. Individual members must satisfy all of their requirements above their purchase obligations from us from other suppliers, unless we and our members agree that we will supply additional capacity and associated energy, subject to the approval requirements described above. ~~In 2020, we supplied energy that accounted for approximately 57% of the retail energy requirements of our members.~~ See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."

Under the wholesale power contracts, each member must establish rates and conduct its business in a manner that will enable the member to pay (i) to us when due, all amounts payable by the member under its wholesale power contract and (ii) any and all other amounts payable from, or which might constitute a charge or a lien upon, the revenues and receipts derived from the member's electric system, including all operation and maintenance expenses and the principal of, premium, if any, and interest on all indebtedness related to the member's electric system.

The New Business Model Member Agreement that we have with our members requires member approval for us to undertake certain activities. The agreement does not limit our ability to own, manage, control and operate our resources or perform our functions under the wholesale power contracts.

We may not provide services unrelated to our resources or our functions under the wholesale power contracts if these services would require us to incur indebtedness, provide a guarantee or make any loan or investment, unless approved by 75% of the members of our board of directors, 75% of our members, and members representing 75% of our patronage capital. We may provide any other unrelated service to a member so long as (i) doing so would not create a conflict of interest with respect to other members, (ii) the service is being provided to all members or (iii) the service has received the three 75% approvals described above.

Each member is required to pay us for capacity and energy we furnish under its wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. We are required to revise our rates as necessary so that the revenues derived from our rates, together with our revenues from all other sources,

Under the first mortgage indenture, we are required, subject to any necessary regulatory approval, to establish and collect rates which are reasonably expected, together with our other revenues, to yield a margins for interest ratio for each fiscal year equal to at least 1.10. The formulary rate is intended to provide for the collection of revenues which, together with revenues from all other sources, are equal to all costs and expenses we recorded, plus amounts necessary to achieve at least the minimum 1.10 margins for interest ratio. In the event we were to fall short of the minimum 1.10 margins for interest ratio at year end, the formulary rate is designed to recover the shortfall from our members in the following year without any additional action by our board of directors.

Under our loan agreements with each of the Rural Utilities Service and Department of Energy, changes to our rates resulting from adjustments in our annual budget are generally not subject to their approval. We must provide the Rural Utilities Service and Department of Energy with a notice of and opportunity to object to most changes to the formulary rate under the wholesale power contracts. See "– Relationship with Federal Lenders." Currently, our rates are not subject to the approval of any other federal or state agency or authority, including the Georgia Public Service Commission.

Our principal financial requirements are contained in the Indenture, dated as of March 1, 1997, from us to U.S. Bank Trust Company, National Association, as trustee (successor to ~~SunTrust Bank)~~U.S. Bank National Association), as amended and supplemented, referred to herein as the first mortgage indenture. The first mortgage indenture constitutes a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. The mortgaged property includes our owned electric generating plants, the wholesale power contracts with our members and some of our contracts relating to the ownership, operation or maintenance of electric generation facilities owned by us.

Under our first mortgage indenture, we are required, subject to any necessary regulatory approval, to establish and collect rates which are reasonably expected, together with our other revenues, to yield a margins for interest ratio for each fiscal year equal to at least 1.10. The margins for interest ratio is determined by dividing margins for interest by total interest charges on debt secured under our first mortgage indenture. Margins for interest is the sum of:

Margins for interest takes into account any item of net margin, loss, gain or expenditure of any of our affiliates or subsidiaries only if we have received the net margins or gains as a dividend or other distribution from such affiliate or subsidiary or if we have made a payment with respect to the losses or expenditures. In addition, our margins include certain items that are excluded from the margins for interest ratio, such as non-cash capital credits allocation from Georgia Transmission Corporation.

Under our first mortgage indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to the distribution, (i) an event of default exists under the first mortgage indenture, (ii) our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of

As of December 31, ~~2020,~~2023, we had approximately ~~$10.6~~$12.1 billion of secured indebtedness outstanding under the first mortgage indenture. From time to time, we may issue additional first mortgage obligations ranking equally and ratably with the existing first mortgage indenture obligations. The aggregate principal amount of obligations that may be issued under the first mortgage indenture is not limited; however, our ability to issue additional obligations under the first mortgage indenture is subject to certain requirements related to the certified value of certain of our tangible property, repayment of obligations outstanding under the first mortgage indenture and payments made under certain pledged contracts relating to property to be acquired.

Historically, federal loan programs administered by the Rural Utilities Service, an agency of the United States Department of Agriculture, have provided the principal source of financing for electric cooperatives. Loans guaranteed by the Rural Utilities Service and made by the Federal Financing Bank have been a major source of funding for us. However, Rural Utilities Service loan funds are subject to annual federal budget appropriations, and, due to budgetary and political pressures faced by Congress, the availability and magnitude of these loan funds cannot be assured. The budget for fiscal year ~~2021,~~2024, which began October ~~2020,~~2023, includes aan aggregate loan program level of ~~$5.5 billion, the same as in recent years. The new Administration has not yet proposed a budget for fiscal year 2022.~~$6.5 billion. We cannot predict the amount or cost of Rural Utilities Service loans that may be available to us in the future.

We have a loan contract with the Rural Utilities Service. Under the loan contract, we may have to obtain approval from the Rural Utilities Service or provide the Rural Utilities Service with a notice and an opportunity to object before we take certain actions, including, without limitation,

As of December 31, ~~2020,~~2023, we had ~~$2.4~~$2.7 billion of outstanding loans guaranteed by the Rural Utilities Service and secured under our first mortgage indenture.

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, we entered into a loan guarantee agreement with the Department of Energy in 2014, pursuant to which the Department of Energy agreed to guarantee over $3.0 billion of our obligations under a multi-advance term loan facility with the Federal Financing Bank. Proceeds of advances made under the facility have been used to reimburse us for a portion of certain costs of construction relating to two additional nuclear units at Plant Vogtle that are eligible for financing under the Title XVII loan guarantee program.

Under the loan guarantee agreement, we may have to obtain approval from the Department of Energy or provide the Department of Energy with a notice and opportunity to object before we take certain actions, including, without limitation,

We and our 38 members are members of Georgia Transmission Corporation (An Electric Membership Corporation), which was formed in 1997 to own and operate the transmission business we previously owned. Georgia Transmission provides transmission services to its members for delivery of its members' power purchases from us and other power suppliers. Georgia Transmission also provides transmission services to third parties. We have entered into an agreement with Georgia Transmission to provide transmission services for third party transactions and for service to our own facilities.

Georgia Transmission has rights in the integrated transmission system, which consists of transmission facilities owned by Georgia Transmission, Georgia Power Company, the Municipal Electric Authority of Georgia and the City of Dalton, Georgia. Through agreements, common access to the combined facilities that compose the integrated transmission system enables the owners to use their combined resources to make deliveries to or for their respective consumers, to provide transmission service to third parties and to make off-system purchases and sales. The integrated transmission system was established in order to obtain the benefits of a coordinated development of the parties' transmission facilities and to make it unnecessary for any party to construct duplicative facilities.

We, Georgia Transmission and our 38 members are members of Georgia System Operations Corporation, which was formed in 1997 to own and operate the system operations business we previously owned. Georgia System Operations operates the system control center and currently provides Georgia Transmission and us with system operations services and administrative support services. We have contracted with Georgia System Operations to schedule and dispatch our resources. We also purchase from Georgia System Operations services that it purchases from Georgia Power under the Control Area Compact, which we co-signed with Georgia System Operations. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Members' Relationship with Georgia Transmission and Georgia System Operations." Georgia System Operations provides support services to us in the areas of accounts payable, payroll, auditing, human resources, campus services, telecommunications and information technology at cost.

Georgia Transmission has contracted with Georgia System Operations to provide certain transmission system operation services including reliability monitoring, switching operations, and the real-time management of the transmission system.

Smarr EMC is a Georgia electric membership corporation owned by 35 of our 38 members. Smarr EMC owns two combustion turbine facilities with aggregate summer planning reserve capacity of ~~737~~733 megawatts. We provide operations, financial and management services ~~for~~to Smarr EMC. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."

Under current Georgia law, our members generally have the exclusive right to provide retail electric service in their respective territories. However, the Georgia Territorial Act permits limited competition among electric utilities located in Georgia for sales of electricity to certain large commercial or industrial customers. The owner of any new facility may receive electric service from the power supplier of its choice if the facility is located outside of municipal limits and has a connected load upon initial full operation of 900 kilowatts or more. Georgia is projected to experience significant load growth over the next several years. Our members are actively engaged in competition with other retail electric suppliers for ~~these~~a significant amount of new commercial and industrial loads. The number of commercial and industrial loads served by our members continues to increase annually. This limited competition has given our members the opportunity to develop resources and strategies to operate in a more competitive market.

Some states have implemented varying forms of retail competition among power suppliers. No legislation related to retail competition has yet been enacted in Georgia which would amend the Georgia Territorial Act or otherwise affect the exclusive right of our members to supply power to their current service territories. However, parties have unsuccessfully sought and will likely continue to seek to advance legislative proposals that will directly or indirectly affect the Georgia Territorial Act in order to allow increased retail competition in our members' service territories. The Georgia Public Service Commission does not have the authority under Georgia law to order retail competition or amend the Georgia Territorial Act.

We routinely consider, along with our members, a wide array of potential actions to meet future power supply needs, maintain competitive rates, adapt to technological innovations, including distributed generation and energy storage technologies, and respond to the evolving competitive and regulatory landscape. We cannot predict at this time the outcome of various developments that may lead to increased competition in the electric utility industry or the effect of any developments on us or our members.

From time to time, individual members may be approached by parties indicating an interest in purchasing their systems. A member generally must obtain our approval before it may consolidate or merge with any person or reorganize or change the form of its business organization from an electric membership corporation or sell, transfer, lease or otherwise dispose of all or substantially all of its assets to any person, whether in a single transaction or series of transactions. A member may enter into such a transaction without our approval if specified conditions are satisfied, including, but not limited to, an agreement by the transferee, satisfactory to us, to assume the obligations of the member under the wholesale power contract, and certifications of accountants as to certain specified financial requirements of the transferee. The wholesale power contracts also provide that a member may not dissolve, liquidate or otherwise wind up its affairs without our approval.

We supply capacity and energy to our members for a portion of their requirements from ~~a combination of~~ our fleet of generating ~~assets and power purchased from other suppliers.~~assets. In ~~2020,~~2023, we supplied approximately ~~57%~~68% of the retail energy requirements of our members. Our members purchased the remaining ~~43%~~32% from a variety of suppliers, including Green Power EMC (renewable resources), Smarr EMC (gas-fired resources)~~, Georgia Energy Cooperative (gas-fired resource)~~, Southeastern Power Administration (hydroelectric power), and several power marketers and other wholesale suppliers. For more detailed information on these other purchases, see "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."

~~Our~~As of December 31, 2023, our fleet of generating units total ~~7,862~~8,525 megawatts of summer planning reserve capacity, including ~~737~~733 megawatts of Smarr EMC assets, which we manage. Our generation portfolio includes interests in nuclear, coal, natural gas, oil and hydro units. Georgia Power, the Municipal Electric Authority of Georgia (MEAG) and the City of Dalton also have interests in ~~nine~~seven of these units at Plants Hatch, Vogtle ~~Wansley~~ and Scherer. Georgia Power serves as operating agent for these ~~nine~~seven units. Georgia Power also has an interest in the three units at Rocky Mountain, which we operate. In addition to our 3133 generating units, we operate and manage six gas-fired generating units on behalf of Smarr EMC.

We currently have no material power purchase or sale agreements.

We have interchange, transmission and/or short-term capacity and energy purchase or sale agreements with a number of power marketers and other power suppliers. The agreements provide variously for the purchase and/or sale of capacity and energy and/or for the purchase of transmission service.

In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc., which

Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Effective in July 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement (the Services Agreement), pursuant to which Westinghouse is providing facility design and engineering services, procurement and technical support and staff augmentation on a time and materials cost basis. The Services Agreement provides that it will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. ~~The Services Agreement is terminable by the Co-owners upon 30 days’ written notice.~~

In October 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, pursuant to which Bechtel serves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement)~~. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel~~ and is reimbursed for actual costs plus a base fee and an at-risk fee, ~~which is~~ subject to adjustment based on Bechtel’s performance against cost and schedule targets. Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events.

On July 31, 2023, Georgia Power placed Unit No. 3 in service.

In connection with the September 2018 vote to continue construction, Georgia Power entered into a binding term sheet with the other Co-owners and MEAG’s wholly-owned subsidiaries MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, and MEAG Power SPVP, LLC ~~that mitigated~~to mitigate certain financial exposure for the other Co-owners and offered to purchase production tax credits from each of the other Co-Owners, at that Co-owner’s option (the Term Sheet). OnIn February ~~18,~~ 2019, the Co-owners entered into the Global Amendments to memorialize the provisions of the Term Sheet. Pursuant to the Global Amendments and consistent with the Term Sheet, the Joint Ownership Agreements provide that:

The ultimate outcome of these matters cannot be determined at this time.

See “RISK FACTORS” for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.

In May 2023, we acquired one generating unit at the Baconton Power Plant, a four-unit 188 megawatt natural gas-fired combustion turbine facility located near Baconton, Georgia, from Baconton Power, LLC. Our unit has an aggregate summer planning reserve generation capacity of approximately 45 megawatts. Our unit also features dual-fuel capability and can run on diesel fuel that is stored on site.

Some of our members elected to take service (scheduling members) at the date of acquisition and some members have elected to defer (deferring members) their share of output until on or before January 2026. Prior to the deferring members’ use of Baconton, their share of output is being sold into the wholesale market. Revenues and costs of output associated with scheduling members are recognized in the current period. Residual net results of operations, including related interest costs of deferring members, are deferred as a regulatory asset. This regulatory asset will be amortized over the then remaining life of the plant, estimated to be 14 years at January 2026. If a deferring member elects to take service before January 2026, amortization of that member's share of the regulatory asset will begin upon taking service.

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~~From time to time,~~Based on significant projected load growth in Georgia, we ~~may assist~~and our members ~~in investigating~~are evaluating potential new power supply resources, ~~after compliance~~to meet our members' anticipated power supply needs and are evaluating potential funding opportunities through the Rural Utilities Service Empowering Rural America program. Before acquiring or constructing any generation resource, we must comply with the terms of the New Business Model Member Agreement. See "OGLETHORPE POWER CORPORATION – New Business Model Member Agreement."

Our members serve approximately ~~2.0~~2.1 million electric consumers (meters) representing approximately ~~4.3~~4.5 million people. Our members serve a region covering approximately 38,000 square miles, which is approximately 65% of the land area in the State of Georgia, encompassing 151 of the State's 159 counties. Historically, our members' sales by customer class have been approximately two-thirds to residential consumers and slightly less than one-third to commercial and industrial consumers. Our members are the principal suppliers for the power needs of rural Georgia. While our members do not serve any major cities, portions of their service territories are in close proximity to urban areas and have experienced substantial growth over the years due to the expansion of urban areas, including metropolitan Atlanta, into suburban areas and the growth of suburban areas into neighboring rural areas. Each year we file an exhibit containing financial and statistical information for our 38 members for the most recent three year period with our first or second quarter Form 10-Q.

The Georgia Territorial Act regulates the service rights of all retail electric suppliers in the State of Georgia. Pursuant to the Georgia Territorial Act, the Georgia Public Service Commission assigned substantially all areas in the State to specified retail suppliers. With limited exceptions, our members have the exclusive right to provide retail electric service in their respective territories, which are predominately outside of the municipal limits existing at the time the Georgia Territorial Act

The Georgia Public Service Commission may reassign territory only if it determines that an electric supplier has breached the tenets of public convenience and necessity. The Georgia Public Service Commission may transfer service for specific premises only if: (i) it determines, after joint application of electric suppliers and proper notice and hearing, that the public convenience and necessity require a transfer of service from one electric supplier to another; or (ii) it finds, after proper notice and hearing, that an electric supplier's service to the premises is not adequate or dependable or that its rates, charges, service rules and regulations unreasonably discriminate in favor of or against the consumer utilizing the premises and the electric utility is unwilling or unable to comply with an order from the Georgia Public Service Commission regarding the service.

The Georgia Territorial Act allows limited competition among electric utilities in Georgia by allowing the owner of any new facility located outside of municipal limits and having a connected load upon initial full operation of 900 kilowatts or greater to receive electric service from the retail supplier of its choice. Georgia is projected to experience significant load growth over the next several years. Our members, with our support, are actively engaged in competition with other retail electric suppliers for ~~these~~a significant amount of new commercial and industrial loads. The number of commercial and industrial loads served by our members continues to increase annually. This limited competition has given our members and us the opportunity to develop resources and strategies to operate in an increasingly competitive market.

For further information regarding members' competitive activities, see "OGLETHORPE POWER CORPORATION – Competition."

Our members are cooperatives that operate their systems on a not-for-profit basis. Accumulated margins derived after payment of operating expenses and provision for depreciation constitute patronage capital of the consumers of our members. Refunds of accumulated patronage capital to the individual consumers may be made from time to time subject to limitations contained in mortgages between the members and the Rural Utilities Service or loan documents with other lenders. The Rural Utilities Service mortgages generally prohibit these distributions unless (i) after any of these distributions, the member's total equity will equal at least 30% of its total assets or (ii) distributions do not exceed 25% of the margins and patronage capital received by the member in the preceding year and equity is at least 20% of total assets. See "– Members' Relationship with the Rural Utilities Service."

We are a membership corporation, and our members are not our subsidiaries. Except with respect to the obligations of our members under each member's wholesale power contract with us and our rights under these contracts to receive payment for power and energy supplied, we have no legal interest in (including through a pledge or otherwise), or obligations in respect of, any of the assets, liabilities, equity, revenues or margins of our members. See "OGLETHORPE POWER CORPORATION – Wholesale Power Contracts." The assets and revenues of our members are, however, pledged under their respective mortgages with the Rural Utilities Service or loan documents with other lenders.

We depend on the revenue we receive from our members pursuant to the wholesale power contracts to cover the costs of operation of our power supply business and satisfy our debt service obligations.

Through provisions in the loan documents securing loans to the members, the Rural Utilities Service exercises control and supervision over the rates for the sale of power of our members that borrow from it. The Rural Utilities Service mortgage indentures of these members require them to design rates with a view to maintaining an average times interest earned ratio and an average debt service coverage ratio of not less than 1.25 and an operating times interest earned ratio and an operating debt service coverage ratio of not less than 1.10, in each case for the two highest out of every three successive years.

The Georgia Electric Membership Corporation Act, under which each of the members was formed, requires the members to operate on a not-for-profit basis and to set rates at levels that are sufficient to recover their costs and to provide for reasonable reserves. The setting of rates by the members is not subject to approval by any federal or state agency or authority

Cobb EMC, Diverse Power Incorporated, an EMC, Mitchell EMC, Oconee EMC, Okefenoke Rural EMC, Snapping Shoals EMC and Walton EMC have repaid all of their Rural Utilities Service indebtedness and are no longer Rural Utilities Service borrowers. Each of these members now has a rate covenant with its current lender. Other members may also pursue this option. To the extent a member that is not a Rural Utilities Service borrower engages in wholesale sales or sales of transmission service in interstate commerce, it would, in certain circumstances, be subject to regulation by the Federal Energy Regulatory Commission under the Federal Power Act.

Through provisions in the loan documents securing loans to the members, the Rural Utilities Service also exercises control and supervision over the members that borrow from it in such areas as accounting, other borrowings, construction and acquisition of facilities, and the purchase and sale of power.

Historically, federal loan programs providing direct and guaranteed loans from the Rural Utilities Service to electric cooperatives have been a major source of funding for the members. Under the current Rural Utilities Service loan programs, electric distribution borrowers are eligible for loans made by the Federal Financing Bank or other lenders and guaranteed by the Rural Utilities Service. Certain borrowers with either low consumer density or higher than average rates and lower than average consumer income are eligible for special loans that bear interest at an annual rate of 5%. However, Rural Utilities Service loan funds are subject to annual federal budget appropriations, and, due to budgetary and political pressures faced by Congress, the availability and magnitude of these loan funds cannot be assured.

Georgia Transmission provides transmission services to our members for delivery of our members' power purchases from us and other power suppliers. Georgia Transmission and the members have entered into member transmission service agreements under which Georgia Transmission provides transmission service to the members pursuant to a transmission tariff. The member transmission service agreements have a minimum term for network service until December 31, 2060. The members' transmission service agreements include certain elections for load growth above 1995 requirements, with notice to Georgia Transmission, to be served by others. These agreements also provide that if a member elects to purchase a part of its network service elsewhere, it must pay appropriate stranded costs to protect the other members from any rate increase that they would otherwise incur. Under the member transmission service agreements, members have the right to design, construct and own new distribution substations.

Georgia System Operations has contracts with each of its members, including Georgia Transmission and us, to provide to them the services that it in turn purchases from Georgia Power under the Control Area Compact, which we co-signed with Georgia System Operations. Georgia System Operations also provides operation services for the benefit of our members through agreements with us, including dispatch of our resources and other power supply resources owned by the members.

For information about our relationship with Georgia System Operations, see "OGLETHORPE POWER CORPORATION – Relationship with Georgia System Operations Corporation."

In ~~2020,~~2023, we supplied approximately ~~57%~~68% of the retail energy requirements of our members. Pursuant to the wholesale power contracts, we supply each member energy from our generation resources based on its fixed percentage capacity cost responsibility, which are take-or-pay obligations. See "OGLETHORPE POWER CORPORATION – Wholesale Power

Thirty-three of our members purchase hydroelectric power from the Southeastern Power Administration, or SEPA, under contracts that will continue until terminated by two years' written notice by SEPA or the respective member. At January 1, ~~2021,~~2024, the aggregate SEPA allocation of capacity to the members was ~~569~~570 megawatts plus associated energy. The availability of energy under these contracts is significantly affected by hydrologic conditions, including lengthy droughts. Each member must schedule its energy allocation, and each member, other than Flint EMC, has designated us to perform this function. Pursuant to a separate agreement, we schedule, through Georgia System Operations, our members' SEPA power deliveries. Further, each member may be required, if certain conditions are met, to contribute funds for capital improvements for U.S. Army Corps of Engineers projects from which its allocation is derived in order to retain the allocation.

Smarr EMC is a Georgia electric membership corporation owned by 35 of our 38 members. Smarr EMC owns two combustion turbine facilities with aggregate capacity of ~~737~~733 megawatts. The 35 members participating in these two facilities purchase the output of those facilities pursuant to separate take-or-pay power purchase agreements that will continue until terminated by one year's written notice by Smarr EMC or the respective member.

Each of our members is also a member of Green Power Electric Membership Corporation, a power supply cooperative specializing in the purchase of renewable energy for its members. Green Power EMC currently purchases energy from ~~320~~756 megawatts of solar, low-impact hydroelectric, landfill gas and wood-waste biomass ~~and solar~~ facilities, with an additional ~~264~~80 megawatts under contract and under construction, with plans to purchase more in the future. Included in this total is energy purchased from Green Power Solar, a for-profit subsidiary of Green Power EMC, which has leased, with an option to purchase, ~~ten~~twelve solar facilities with a total of approximately 10 megawatts.

We have not undertaken to obtain a comprehensive list of member power supply resources. Any of our members may have committed or may commit to additional power supply obligations not described above.

For information about members' activities relating to their power supply planning, see "OGLETHORPE POWER CORPORATION – Competition" and "OUR POWER SUPPLY RESOURCES – Future Power Resources." In addition to future power supply resources that we may construct or acquire for our members, the members will likely also continue to acquire future resources from other suppliers, including suppliers that may be owned by members.

As an electric utility, we are subject to a wide range of federal, state and local environmental laws. Air emissions, solid waste disposal, effluent water discharges, and water usage are extensively controlled, closely monitored, and periodically reported. The manner in which various types of wastes can be stored, transported and disposed is also comprehensively regulated.

In general, environmental requirements applicable to the electric power sector are becoming increasingly prescriptive and ~~stringent.~~stringent, and the Environmental Protection Agency, or EPA, intends to finalize a number of rules in 2024 that could impact our power plants. Although we have installed an extensive array of environmental control systems at our plants to ensure continued compliance with all existing applicable requirements, including systems to reduce emissions of sulfur dioxide, nitrogen oxides, mercury and other regulated air pollutants, ~~at Plants Scherer and Wansley,~~ new environmental regulatory requirements could be imposed. Such additional requirements, if adopted, could substantially increase the cost of electric service by requiring modifications in the design or operation of existing ~~facilities.~~facilities and making new facilities more difficult to site and more expensive to build. Failure to comply with these requirements could result in us becoming subject to enforcement actions and the assessment of civil ~~and criminal penalties and~~penalties. In extreme cases of non-compliance, such enforcement actions could even ~~require~~include the complete shutdown of individual generating ~~units not in compliance in some cases.~~units. Certain of our debt instruments also require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to comply with these requirements, it would constitute a default under those debt instruments. Although we intend to comply with all current and future regulations, we cannot guarantee that we will always be in full compliance with every applicable requirement.

Environmental regulations adopted at the federal and state levels have had and will continue to have a significant impact on the electric utility industry. The most significant environmental regulations for us continue to be the air regulatory requirements imposed under the Clean Air Act. These requirements include stringent regulations for controlling emissions of sulfur dioxide, nitrogen oxides, particulate matter, mercury, greenhouse gases, and other air pollutants from affected electric utility ~~units, including the coal-fired units at Plants Scherer and Wansley.~~units. The ~~Environmental Protection Agency, or~~ EPA has actively regulated emissions under the Clean Air Act and the following are the most significant ongoing Clean Air Act regulatory requirements that affect or may affect our business.

On December 2, 2019, EPA issued a proposed rule to establish new deadlines by which unlined surface impoundments may no longer receive CCR waste and non-CCR wastestreams. EPA proposed additional revisions to the CCR rule in February 2020 that clarified circumstances under which alternative liners may be used, when coal ash may be used in the closure of landfills and impoundments, and that post-closure groundwater monitoring is required if coal ash is removed from a landfill or impoundment. In 2019, Georgia Power ceased sending CCR to the ash ponds at Plants Scherer and Wansley. Similarly, Georgia Power has installed a new wastewater treatment system that will receive and manage the non-CCR wastestreams at Scherer. As a result, these new closure deadlines ~~are~~have not ~~expected to impact~~impacted our operations. Although no litigation related to CCR regulations is now pending, we cannot predict whether there will be any future lawsuits on the requirements for closing these impoundments or remedying any impacts of the impoundments may be having on groundwater.

In 2015, the U.S. Court of Appeals for the Sixth Circuit stayed a final rule published jointly by EPA and the U.S. Army Corps of Engineers that revised the regulatory definition of waters of the U.S. for all Clean Water Act programs. The final rule would have significantly expanded the scope of federal jurisdiction under the Clean Water Act. Although the rule was not expected to have a substantial direct impact on our existing operations, it would likely have increased permitting and regulatory

We are subject to other environmental statutes including, but not limited to, the Georgia Water Quality Control Act, the Georgia Hazardous Site Response Act, the Toxic Substances Control Act, the Endangered Species Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Emergency Planning and Community Right to Know Act, and the regulations implementing these environmental statutes. We do not believe that our compliance obligations with these ~~statutes~~statutory and ~~regulations~~regulatory requirements will have a material impact on our financial condition or operation of our facilities. Changes to any of these laws, however, could affect many areas of our operations. Although compliance with new environmental legislation could have a significant impact on those operations, such impacts cannot be fully determined at this time and would depend in part on the final legislation and the development of implementing regulations.

As an owner, co-owner and/or operator of generating facilities, we are also subject, from time to time, to claims relating to operations and/or emissions, including actions by citizens to enforce environmental regulations and claims for personal injury due to such operations and/or emissions. Likewise, actions by private citizen groups to enforce environmental laws and regulations are becoming increasingly prevalent. We cannot predict the outcome of current or future actions, our responsibility for a share of any damages awarded, or any impact on facility operations. We do not believe, however, that current actions will have a material adverse effect on our financial ~~position,~~condition or results of ~~operations or cash flows.~~operations.

While we will continue to exercise our best efforts to comply with all applicable regulations, there can be no assurance that we will always be in full compliance with all applicable current and future environmental requirements. Failure to

We are subject to the provisions of the Atomic Energy Act of 1954 (the Atomic Energy Act), which vests jurisdiction in the Nuclear Regulatory Commission over the construction and operation of nuclear reactors, particularly with regard to certain public health, safety and antitrust matters. The National Environmental Policy Act has been construed to expand the jurisdiction of the Nuclear Regulatory Commission to consider the environmental impact of a facility licensed under the Atomic Energy Act. Plants Hatch and Vogtle are being operated under licenses issued by the Nuclear Regulatory Commission. All aspects of the construction, operation and maintenance of nuclear power plants are regulated by the Commission. From time to time, new Commission regulations require changes in the design, operation and maintenance of existing nuclear reactors. Operating licenses issued by the Commission are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the Commission determines that the public interest, health or safety so requires. The operating licenses issued for ~~each unit of Plants~~Plant Hatch Units No. 1 and ~~Vogtle~~No. 2 expire in 2034 and 2038, respectively, and for Plant Vogtle Units No. 1, No. 2, No. 3 and No. 4 expire in 2047, 2049, 2062 and ~~2049,~~2063, respectively. Southern Nuclear has notified the Nuclear Regulatory Commission of its intent to seek to renew Plant Hatch Units No. 1 and No. 2 licenses for an additional 20 years, through 2054 and 2058, respectively.

Pursuant to the Nuclear Waste Policy Act of 1982, the federal government has the responsibility for the final disposal of commercially produced high-level radioactive waste materials, including spent nuclear fuel. This act requires the owner of nuclear facilities to enter into disposal contracts with the Department of Energy for such material.

Contracts with the Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants, has successfully pursued and continues to pursue legal remedies against the Department of Energy for breach of contract. See Note 1 of Notes to Consolidated Financial Statements for information regarding the status of this litigation.

In November 2013, the U.S. District Court for the District of Columbia ordered the Department of Energy to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the Department of Energy either complies with the Nuclear Waste Policy Act of 1982 or until the U.S. Congress enacts an alternative waste management plan. We discontinued paying the fee of approximately $9.2 million annually, based on our ownership interests, in June 2014.

~~Existing~~We expect existing on-site dry storage facilities at Plants Hatch and Vogtle can be expanded to accommodate spent fuel through the expected life of each plant, including Vogtle Units No. 3 and No. 4.

For information concerning nuclear insurance, see Note 10 of Notes to Consolidated Financial Statements. For information regarding the Nuclear Regulatory Commission's regulation relating to decommissioning of nuclear facilities and regarding the Department of Energy's assessments pursuant to the Energy Policy Act for decontamination and decommissioning of nuclear fuel enrichment facilities, see Note 1 of Notes to Consolidated Financial Statements.

Pursuant to the Federal Power Act, the Federal Energy Regulatory Commission is the federal agency that regulates the nation's bulk power system. We are subject to certain rules and regulations under the Federal Power Act; however, as a

The Energy Policy Act of 2005 amended the Federal Power Act to authorize the Federal Energy Regulatory Commission to establish an electric reliability organization to develop and enforce mandatory reliability standards and to establish clear responsibility for the commission to prohibit manipulative energy trading practices. In 2006, the Federal Energy Regulatory Commission certified the North American Electric Reliability Corporation, or NERC, as the electric reliability organization. The mandatory reliability standards developed by NERC and approved by the Federal Energy Regulatory Commission impose certain operating, coordination, record-keeping and reporting requirements on us. NERC has delegated day-to-day enforcement of its responsibilities to regional entities and SERC Reliability Corporation is the regional entity to enforce

As a generator owner and generator operator, we are subject to certain of these mandatory reliability standards. We have established a comprehensive formal compliance program to establish, monitor, maintain and enhance our commitment to electric reliability compliance. This program includes comprehensive cyber security elements designed to protect and preserve our critical information and energy infrastructure systems. Although we intend to comply with all currently effective and enforceable reliability standards, we cannot provide assurance that we will always be in compliance. We are obligated to maintain and retain evidence of compliance with specific requirements. SERC Reliability Corporation also regularly monitors us for compliance with reliability standards. We expect that existing reliability standards will continue to be refined and that new reliability standards will be developed or adopted.

The Nuclear Regulatory Commission has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. If our nuclear facilities were found to be out of compliance with applicable requirements, the Nuclear Regulatory Commission may impose fines or shut down one or more units of these facilities until compliance is achieved. Revised safety requirements issued by the Nuclear Regulatory Commission have, in the past, necessitated substantial capital expenditures at other nuclear generating facilities.

Further, a major incident at a nuclear facility anywhere in the world could cause the Nuclear Regulatory Commission to limit or prohibit the operation or licensing of any domestic nuclear unit. While we have no reason to expect a serious incident at either of our nuclear plants, if an incident did occur, it could result in substantial cost to us.

Further, a significant percentage of our energy is generated at co-owned facilities that are operated by Georgia Power and Southern Nuclear. We rely on these third parties for the continued operation of these facilities to avoid potential interruptions in service from these facilities. If these third parties are unable to operate these facilities, the cost of electric service we provide to our members, or the cost of replacement electric service, may increase. See “BUSINESS—OGLETHORPE POWER CORPORATION—Relationship with Georgia Power Company” and “Properties—Co-Owners of Plants” and “—Plant Agreements” for discussions of our relationship with Georgia Power and our co-owned facilities.

We rely on access to external funding sources as a significant source of liquidity for capital expenditures and acquisitions not satisfied by cash flow generated from operations. Unlike most investor-owned utilities, electric cooperatives cannot issue equity securities and therefore rely almost entirely on debt financing.

Historically, we relied on federal loan programs guaranteed by the Rural Utilities Service, a branch of the U.S. Department of Agriculture, in order to meet a significant portion of our long-term financing needs, typically at a cost that was lower than traditional capital markets financing. However, the availability and magnitude of Rural Utilities Service funding levels are subject to the annual federal budget appropriations process, and therefore are subject to uncertainty because of budgetary and political pressures faced by Congress. If the amount of this funding available to us in the future is decreased or eliminated, we would seek alternative sources of debt financing in the traditional capital markets which would likely be at a higher cost.

Our borrowing costs are also affected by prevailing interest rates. If interest rates have increased at the time we issue fixed rate debt or reset the interest rates on our variable rate debt, our interest costs will increase and our financial condition and future results of operations could be adversely affected.

In addition, market disruptions could constrain, at least temporarily, lenders’ willingness or ability to perform their obligations under existing credit agreements and our ability to access additional sources of capital on favorable terms or at all. These disruptions include:

Further, an increasing number of lenders and investors are taking into account environmental, social and corporate governance criteria when making lending and investment decisions. Although we are not aware of any instances where our access to capital was limited due to these criteria, such considerations could potentially limit the number of lenders or investors who are willing to lend capital to us or other utility companies in the future.

In order to increase financial coverage during this period of generation expansion, our board of directors has approved budgets to achieve margins for interest ratios greater than the minimum 1.10 margins for interest ratio required under our first mortgage indenture. We have achieved the board-approved margins for interest ratio each year, and for ~~2021~~2024 our board of directors again approved a margins for interest ratio of 1.14.

We depend primarily on revenue from our members under the wholesale power contracts to meet our financial obligations. Our members are our owners, and we do not control their operations or financial performance.

We follow generally accepted accounting principles in the United States and the practices prescribed in the Uniform System of Accounts of the Federal Energy Regulatory Commission as modified and adopted by the Rural Utilities Service.

We have determined that the following accounting policies are critical to understanding and evaluating our financial condition and results of operations and requires our management to make estimates and assumptions about matters that were uncertain at the time of the preparation of our financial statements. Changes in these estimates and assumptions by our management could materially impact our results of operations and financial condition. Our management has discussed these critical accounting policies and the related estimates and assumptions with the audit committee of our board of directors.

A significant portion of our asset retirement obligations relates to our share of the future cost to decommission our operating nuclear units and the coal ash ponds at our coal-fired units. At December 31, ~~2020,~~2023, our nuclear decommissioning and coal ash related asset retirement obligations were ~~$738.2~~$929.8 million and ~~$346.6~~$464.0 million, respectively. Our asset retirement obligations represent an estimate of the present value of anticipated retirement costs. For additional detail regarding our asset retirement obligations, see Note 1h of Notes to Consolidated Financial Statements. These obligations represented 95% of our total asset retirement obligations.

Given its significance, we consider our nuclear decommissioning liabilities critical estimates. Approximately every three years, new decommissioning studies for Plants Hatch and Vogtle are performed. These studies provide us with periodic site-specific "base year" cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for the plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of the amount and timing of future cash flows for extended periods are by nature highly uncertain and may vary significantly from actual costs. In addition, these estimates are dependent on subjective factors, including the selection of cost escalation and discount rates, which we consider to be critical assumptions. Our current estimates are based upon studies that were performed in ~~2018.~~2020 and 2021. For ratemaking purposes, we record decommissioning costs over the expected service life of each unit. The impact on measurements of asset retirement obligations using different assumptions in the future may be significant.

We operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. Our primary source of revenue is the sale of capacity and energy to our members for a portion of their energy requirements. We may also sell capacity and energy to non-members. Capacity revenues are the revenues we receive for providing electric service whether or not our generation and purchased power resources are dispatched to produce electricity. Energy revenues are the revenues we receive by selling electricity that we generate or purchase.

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Each member is also contractually obligated to pay us for electric energy we provide to it based on individual usage. Energy sales to our members fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in the service territories of our members, operating costs, availability of electric generation resources and our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights. In addition, as we do not provide our members with all of their energy requirements, energy sales may also fluctuate based on our members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.

The rates we charge our members are designed to cover all of our costs plus a margin. This cost-plus rate structure is set forth as a formula in the rate schedule to the wholesale power contracts between us and each of our members. These contracts require us to design capacity and energy rates that generate revenues sufficient to recover all costs, including payments of principal and interest on our indebtedness, to establish and maintain reasonable margins and to meet the financial coverage requirements under the first mortgage indenture.

The formulary rate provides for the pass through of our fixed costs to members as capacity charges and our variable costs to members as energy charges. Fixed costs are assigned to members according to their individual fixed percentage capacity cost responsibility for each resource in which they participate. Variable costs are passed through to our members based on the amount of energy supplied to each member.

Capacity charges are based on an annual budget of fixed costs plus a targeted margin and are billed to members in equal monthly installments over the course of the year. Fixed costs include items such as depreciation, interest, fixed operations and maintenance expenses, administrative and general expenses. We monitor fixed cost budget variances to projected actual costs throughout the year, and with board approval, make budget adjustments when and as necessary to ensure that we generate revenues sufficient to recover all costs and to meet our targeted margin. Budget adjustments are typically made twice a year; once during the first quarter and again at year end. In contrast to the way we bill our members for capacity charges, which are billed based on a budget and trued up to actuals by the end of the year, energy charges are billed on a more real-time basis. Estimated energy charges are billed to members based on the amount of energy supplied to each member during the month, and are adjusted when actual costs are available, generally the following month. Energy charges, or variable costs, include fuel, purchased energy and variable operations and maintenance expenses. Each generating resource has a different variable cost profile, and members are billed based on the energy cost profile of the resources from which their energy is supplied.

Revenues in excess of current period costs in any year are designated as net margin in our statements of revenues and expenses, and we have generated a positive net margin every year since our formation in 1974. Under our first mortgage indenture, we are required, subject to any necessary regulatory approval, to establish and collect rates that are reasonably expected, together with our other revenues, to yield a margins for interest ratio for each fiscal year equal to at least 1.10. See "BUSINESS – OGLETHORPE POWER CORPORATION – First Mortgage Indenture" for a discussion of how we calculate our margins for interest ratio.

In the event we were to fall short of the minimum 1.10 margins for interest ratio at year end, the formulary rate is designed to recover the shortfall from our members in the following year without any additional action by our board of directors.

Prior to 2009, we budgeted and achieved annual margins for interest ratios of 1.10, the minimum required by the first mortgage indenture. To enhance margin coverage during a period of increased capital requirements, our board of directors has approved budgets with margins for interest ratios that exceeded 1.10. Since 2010, we have achieved our board approved margins for interest ratio of 1.14, and our board has approved a margins for interest ratio of 1.14 for ~~2021.~~2024. As our capital requirements continue to evolve, our board will continue to evaluate the level of margin coverage and may choose to change the targeted margins for interest ratio in the future, although not below 1.10.

Retained net margins are designated on our balance sheets as patronage capital. As a cooperative, patronage capital constitutes our principal equity. As of December 31, ~~2020,~~2023, we had ~~$1.1~~$1.3 billion in patronage capital and membership fees. Our equity ratio, calculated pursuant to our first mortgage indenture as patronage capital and membership fees divided by total capitalization and long-term debt due within one year, was ~~9.1%~~9.4% and ~~9.4%~~9.0% at December 31, ~~2020~~2023 and ~~2019,~~2022, respectively.

Patronage capital is allocated to each of our members on the basis of their fixed percentage capacity cost responsibilities in our generation resources. Any distribution of patronage capital is subject to the discretion of our board of directors and limitations under our first mortgage indenture. See "BUSINESS – OGLETHORPE POWER CORPORATION – First Mortgage Indenture" for a discussion regarding limitations on distributions under our first mortgage indenture.

Under our loan agreements with each of the Rural Utilities Service and Department of Energy, changes to our rates resulting from adjustments in our annual budget are generally not subject to their approval. We must provide the Rural Utilities Service and Department of Energy with a notice of and opportunity to object to most changes to the formulary rate under the wholesale power contracts. See "BUSINESS – OGLETHORPE POWER CORPORATION – Relationship with Federal Lenders." Currently, our rates are not subject to the approval of any other federal or state agency or authority, including the Georgia Public Service Commission.

While we are a not-for-profit membership corporation formed under the laws of Georgia, we are subject to federal and state income taxation. As a taxable cooperative, we are allowed to deduct patronage dividends that we allocate to our

Certain of our recent financial and operational results were affected both by the way in which we dispatch our power plants as well as by significant events or trends described below.

Decisions to dispatch our power plants and thus the amount of energy we generate and sell to our members are economically driven by supply and demand considerations. The primary supply considerations include (i) fuel prices and other marginal operating costs of the plant, which factor into a dispatch cost we calculate for each resource, (ii) plant availability, which is driven by factors such as outages for maintenance or refuelings and (iii) plant efficiency, as determined by the heat rate which measures the amount of fuel required to generate one kilowatt hour of electricity. We prioritize the order in which we typically dispatch our plants such that we dispatch our available plants with the lowest dispatch cost first, and those with the highest dispatch cost last, when demand is highest.

The primary demand consideration that affects how we dispatch our plants is the amount of energy our members require from us. This is a function of weather, economic activity, residential use patterns and the relative cost and availability of our members' third party supply arrangements, which account for approximately a ~~significant portion~~third of the energy they purchase.

In addition to the prevailing market price, our average cost of natural gas per ~~kilowatt hour~~kilowatt-hour generated is also affected by how efficiently our natural gas facilities burn the gas. Compared to our combustion turbine units, our combined cycle units ~~our combustion turbine units~~ are ~~less~~more efficient and ~~thus~~ burn ~~more~~less gas per kilowatt hour of electricity generated. Consequently, our combustion turbine units have a higher dispatch cost than our combined cycle units and are typically used to generate energy only during periods of higher electricity demand, such as on hot summer days or colder winter days. ~~In 2020,~~And although 2023 had milder weather overall, more extreme weather days in 2023 resulted in significantly higher generation from our ~~combustion turbine~~combined cycle units wa~~s less~~compared to 2022 and 2021 and this also contributed to higher member sales (in megawatt-hours) in 2023, than in ~~2019 due to the aforementioned mild weather~~.

Production costs can vary due to the number and extent of outages in a given year. Production costs ~~increased 4.3%~~decreased 11.8% in ~~2020~~2023 compared to ~~2019~~2022 and ~~decreased 1.7%~~increased 14.1% in ~~2019~~2022 compared to ~~2018.~~2021. The ~~increase~~decrease in ~~2020~~2023 was due to less costly planned major maintenance outages ~~at Plant Smith~~ during ~~the year.~~2023 compared to 2022. The ~~decrease~~increase in ~~2019~~2022 was due to ~~a reduction in fixed~~more costly planned major maintenance outages and ~~variable maintenance costs driven by outages~~the result of deferring BC Smith's effects on net margin during ~~the prior year.~~

Depreciation and amortization expense increased 16.4% in 2023 compared to 2022 primarily as a result of ~~lower investment balances~~higher depreciation expense related to Plant Vogtle Unit No. 3 being placed in service on July 31, 2023. Depreciation and ~~lower interest rates.~~ amortization expense increased in 2022 compared to 2021 primarily as a result of higher depreciation rates that went into effect in 2022, as well as the addition of BC Smith which was acquired in 2021.

The ~~6.0% decrease~~12.2% increase in other income in ~~2019~~2023 compared to ~~2018~~2022 was primarily due to ~~losses realized on the retirement~~higher interest income as a result of ~~certain leasehold improvements.~~higher interest rates in 2023 compared to 2022. Total other income was relatively unchanged in 2022 compared to 2021.

~~Allowance for debt funds used during construction~~Interest expense increased in ~~2020 and 2019~~2023 primarily due to ~~increased borrowings or~~higher interest rates on commercial paper which is used as interim financing for Plant Vogtle Units No. 3 and No. 4 construction ~~expenditures.~~expenditures and plant acquisitions. Allowance for debt funds used during construction decreased in 2023 due to Plant Vogtle Unit No. 3 being placed in service on July 31, 2023. As a result of these factors, net interest charges increased 42.9% in 2023. Net interest charges were relatively flat in 2022 as the increased interest expense, which was largely due to increased borrowings for Plant Vogtle construction expenditures, was offset by a corresponding increase in allowance for debt funds used during construction.

Consistent with our budgeted margin for ~~2020,~~2023, we achieved a 1.14 margins for interest ratio which produced a net margin of ~~$55.9~~$65.8 million. This net margin increased our total patronage capital (our equity) and membership fees to ~~$1.1~~$1.3 billion at December 31, ~~2020.~~2023. Our ~~2021~~2024 budget again targets a 1.14 margins for interest ratio.

Our equity to total capitalization ratio, as defined in our first mortgage indenture, was ~~9.1% at December 31, 2020 and~~ 9.4% at December 31, ~~2019.~~2023 and 9.0% at December 31, 2022. We anticipate that our equity ratio will remain around its current level during the remainder of the Vogtle construction period; however, the absolute level of patronage capital will continue to increase.

We had a strong liquidity position at December 31, ~~2020~~2023 with ~~$1.6~~$1.7 billion of unrestricted available liquidity, including ~~$405.5~~$490.6 million of cash and cash equivalents. We issued commercial paper throughout the year to provide interim financing for the Plant Vogtle construction, the Washington County and Baconton acquisitions and for other ~~purposes at a low cost.~~general purposes. The average cost of funds on the ~~$383.5~~$607.9 million of commercial paper outstanding at December 31, ~~2020~~2023 was ~~0.3%~~5.7%.

Restricted cash and short-term investments decreased by $104.1 million at December 31, 2023 compared to December 31, 2022. The decrease was due to the utilization of remaining funds on deposit with the Rural Utilities Service in

See ~~Note��~~Note 7 in Notes to Consolidated Financial Statements for additional information regarding these loans.

See "BUSINESS – OGLETHORPE POWER CORPORATION – Relationship with Federal Lenders" for further discussion of our relationship with the Department of Energy and Rural Utilities Service.

Net cash provided by operating activities was ~~$511.4~~$194.5 million in ~~2020,~~2023, and averaged ~~$450.8~~$433.8 million per year for the three-year period ~~2018~~2021 through ~~2020.~~2023.

We have the flexibility to use the $1.2 billion syndicated line of credit for several purposes, including borrowing for general corporate purposes, issuing letters of credit and backing up commercial paper.

Our unsecured committed lines of credit permit the issuance of up to $960 million in letters of credit on our behalf, of which $957 million remained available at December 31, 2023. This letter of credit issuance capacity includes $500 million under our $1.2 billion syndicated line of credit, $350 million under our JPMorgan Chase line of credit, and ~~environmental improvements.~~$110 million under our CFC line of credit.

Between projected cash on hand and the credit arrangements currently in place, we believe we have sufficient liquidity to cover normal operations and our interim financing needs, including interim financing for the new Vogtle units, until long-term financing is obtained.

Three of our line of credit facilities contain similar financial covenants that require us to maintain minimum patronage capital levels. Currently, we are required to maintain minimum patronage capital of $750 million. As of December 31, ~~2020,~~2023, our patronage capital balance was ~~$1.1~~$1.3 billion. These agreements contain an additional covenant that limits our secured indebtedness and our unsecured indebtedness, both as defined in the credit agreements, to $14 billion and $4 billion, respectively. At December 31, ~~2020,~~2023, we had ~~$10.6~~$12.1 billion of secured indebtedness outstanding and ~~$383.5~~$607.9 million of unsecured indebtedness outstanding.

Under our power bill prepayment program, members can prepay their power bills from us at a discount for an agreed number of months in advance, after which point the funds are credited against the participating members' monthly power bills. At December 31, ~~2020,~~2023, we had ~~nine~~seven members participating in the program and a balance of ~~$144.2~~$78.5 million remaining to be applied against future power bills.

All of the approved Rural Utilities Service-guaranteed loans are funded through the Federal Financing Bank, and the debt is secured ratably with all other debt under our first mortgage indenture.

We are currently discussing the development of additional generation resources with our members to meet projected load growth that are not included in the table above. If our members approve one or more new generation resources, our projected capital expenditures could increase significantly.

We are currently subject to extensive environmental regulations and may be subject to future additional environmental regulations, including future implementation of existing laws and regulations. Since alternative legislative and regulatory environmental compliance programs continue to be debated on a state and national level, we cannot predict what capital costs may ultimately be required. Therefore, environmental expenditures included in the above table only include amounts related to budgeted projects to comply with existing and certain well-defined rules and regulations and do not include amounts related to compliance with other, less certain rules.

Depending on how we and the other co-owners of ~~Plants~~Plant Scherer ~~and Wansley~~ choose to comply with any future legislation or regulations, both capital expenditures and operating expenditures may be impacted. As required by the wholesale power contracts, we expect to be able to recover from our members all capital and operating expenditures made in complying with current and future environmental regulations.

For additional information regarding environmental regulation, see "BUSINESS – REGULATION – Environmental."

The table below sets forth our current ratings from S&P Global Ratings, Moody's Investors Service and Fitch Ratings.

We have financial and other contractual agreements in place containing provisions which, upon a credit rating downgrade below specified levels, may require the posting of collateral in the form of letters of credit or other acceptable

At senior secured rating levels:

At senior unsecured or issuer rating levels:

The Rural Utilities Service Loan Contract contains covenants that, upon a credit rating downgrade below investment grade by two rating agencies, could result in restrictions on issuing debt. Certain of credit agreements and pollution control bond agreements contain provisions based on our ratings that, upon a credit rating downgrade below specified levels, could result in increased interest rates. Also, borrowing rates, letter of credit fees and commitment fees in two of our lines of credit agreements are based on credit ratings and could increase if our ratings are lowered. None of these covenants and provisions, however, would result in acceleration of any debt due to credit rating downgrades.

Given our current level of ratings, our management does not have any reason to expect a downgrade that would result in any material impacts to our business. However, our ratings reflect only the views of the rating agencies and we cannot give any assurance that our ratings will be maintained at current levels for any period of time.

Due to our cost-based rate structure, we have limited exposure to market risks. However, changes in interest rates, equity prices, and commodity prices may result in fluctuations in member rates. We use derivatives only to manage this volatility and do not use derivatives for speculative purposes.

We have an executive risk management and compliance committee that provides general oversight over corporate compliance and all risk management activities, including, but not limited to, commodity trading, fuels management, insurance procurement, debt management, investment portfolio management, environmental compliance, and electric reliability compliance. This committee is comprised of our chief executive officer, chief operating officer, chief financial officer and the executive vice president, member ~~and external~~ relations. The risk management and compliance committee has implemented comprehensive risk management policies to manage and monitor credit, market price, and other corporate risks. These policies also specify controls and authorization levels related to various risk management activities. The committee frequently meets to review corporate exposures, risk management strategies, hedge positions, and compliance matters. The audit committee of our board of directors receives regular reports on corporate exposures, risk management and compliance activities and the actions of the risk management and compliance committee. For further discussion of our board of director's oversight of risk management and compliance, see "DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE – Board of Directors' Role in Risk Oversight."

At December 31, ~~2020,~~2023, the weighted average interest rate on our variable rate debt was ~~0.4%~~5.5%. If, during ~~2021,~~2023, interest rates on this debt changed a hypothetical 100 basis points on the respective repricing dates and remained at that level for the remainder of the year, annual interest expense would change by approximately ~~$7.3~~$7.7 million.

Our objective in managing interest rate risk is to maintain a balance of long-term fixed, intermediate-term fixed and variable rate debt that will lower our overall borrowing costs within reasonable risk parameters. At December 31, ~~2020,~~2023, we had ~~6.8%~~6.3% of our total debt, including commercial paper, classified as variable rate and ~~3.8%~~2.5% of our total debt classified as intermediate-term fixed rate. The remaining ~~89.4%~~91.2% of our debt was classified as long-term fixed rate.

The operative documents underlying the pollution control bond debt contain provisions that allow us to convert the debt that is not fixed to maturity to a variety of variable interest rate modes (such as daily, weekly, monthly, commercial paper, or term rate mode), or to convert the debt to a fixed rate of interest to maturity. Having these interest rate conversion options improves our ability to manage our exposure to variable interest rates.

In addition to interest rate risk on existing debt, we are exposed to the risk of rising interest rates due to the ~~significant amount of~~ new long-term debt we expect to incur in connection with anticipated capital expenditures ~~particularly~~and planned debt refinancings, such as for the ~~construction~~remaining issuance of long-term debt related to Vogtle Units No. 3 and No. 4, and for recent and upcoming acquisitions, as well as the short-term debt we are using for interim financing of ~~this project.~~our various projects.

We maintain external trust funds (reflected as "Nuclear decommissioning trust fund" on the balance sheet) to fund our share of certain costs associated with the decommissioning of our nuclear plants as required by the Nuclear Regulatory Commission. We also maintain an internal reserve for decommissioning (included in "Long-term investments" on the balance

The allocation of equity and fixed income securities in both the external and internal funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs; however, the equity portion of these funds is exposed to price fluctuations in equity markets, and the values of fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor the investment performance of the funds and periodically review asset allocation in accordance with our nuclear decommissioning fund investment policy. Our investment policy establishes targeted and permissible investment allocation ranges for equity and fixed income securities. The targeted asset allocation is diversified among various asset classes and investment styles. Specific investment guidelines are established with each of the investment advisors that are selected to manage a particular asset class or subclass.

The investment guidelines for equity securities typically limit the type of securities that may be purchased and the concentration of equity holdings in any one issuer and within any one sector. With respect to fixed-income securities, the investment guidelines set forth limits for the type of bonds that may be purchased, state that investments be primarily in securities with an assigned investment grade rating of BBB- or above and establish that the average credit quality of the portfolio typically be A+/A1 or higher.

A 10% decline in the value of the internal and external funds' equity and fixed income securities as of December 31, ~~2020~~2023 would result in a loss of value to the funds of approximately ~~$47.5~~$81.7 million.

We are also exposed to the risk of changing prices for fuels, including coal and natural gas.

We have interests in ~~1,501~~982 megawatts of coal-fired nameplate capacity at ~~Plants Scherer and Wansley.~~Plant Scherer. We purchase coal under term contracts and in spot-market transactions. Some of our coal contracts provide volume flexibility and most have fixed or capped prices. Our existing contracts and ~~coal~~ stockpile are expected to provide fixed prices for ~~up to 95%~~100% and ~~100%~~60% of our ~~remaining 2021~~ forecasted coal requirements ~~at Plants Scherer~~for 2024 and ~~Wansley,~~2025, respectively.

The objective of our coal procurement strategy is to ensure reliable coal supply and some price stability for our members. Our strategy permits coal commitments for up to 7 years. The procurement guidelines provide for layering in fixed and/or capped prices by annually entering into coal contracts for a portion of projected coal need for up to 7 years.

We maintain a natural gas hedge program, which assists our participating members in managing potential fluctuations in our power rates to them due to changes in the market price of natural gas. Currently, 1819 of our members have elected to participate in our natural gas hedging program. This program layers in fixed prices for a portion of our forecasted natural gas requirements over a rolling time horizon of up to five and a half years. Natural gas swap arrangements are used for hedging

Our exposure to changes in interest rates, the ~~price~~value of ~~equity securities~~investments we hold, and commodity prices have not changed materially from the previous reporting period.

Oglethorpe Power Corporation is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, Georgia that operates on a not-for-profit basis. We are owned by 38 retail electric distribution cooperative members in Georgia. We provide wholesale electric power from a combination of owned and co-owned generating units of which our ownership share totals ~~7,125~~7,792 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns ~~737~~733 megawatts of summer planning reserve capacity. In addition, we supply financial and management services to Green Power EMC, which purchases energy from renewable energy facilities totaling ~~320~~756 megawatts of capacity, including ~~288~~724 megawatts sourced by solar energy. Georgia Power Company is a co-owner and the operating agent of our nuclear and coal-fired generating units. ~~Our members in turn distribute energy on a retail basis to approximately 4.3 million people.~~

We follow generally accepted accounting principles in the United States. We maintain our accounts in accordance with the Uniform System of Accounts of the Federal Energy Regulatory Commission as modified and adopted by the Rural Utilities Service. We also apply the accounting guidance for regulated operations.

We are organized and operate as a cooperative. Our members paid a total of $190 in membership fees. Patronage capital includes retained net margin. Any excess of revenues over expenditures from operations is treated as an advance of capital by our members and is allocated to each member on the basis of their fixed percentage capacity cost responsibilities in our ~~generation.~~generation resources.

Any distributions of patronage capital are subject to the discretion of our board of directors, subject to first mortgage indenture requirements. Under our first mortgage indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to, (i) an event of default exists under the indenture, (ii) our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of our total long-term debt and equities exceeds 35% of our aggregate net margins earned after such date. This last restriction, however will not apply if, after giving effect to such distribution, our equity as of the end of the immediately preceding fiscal quarter is not less than 30% of our long-term debt and equities.

We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For the years ~~2020, 2019~~2023, 2022 and ~~2018,~~2021, we achieved a margins for interest ratio of 1.14.

Receivables from contracts with our members at December 31, ~~2020~~2023 and December 31, ~~2019~~2022 were ~~$135,462,000~~$170,901,000 and ~~$142,946,000,~~$187,401,000, respectively.

A substantial portion of our receivables are related to capacity and energy sales to our members. These receivables are recorded at the invoiced amount and do not bear interest. Our members are required through the wholesale power contracts to reimburse us for all costs, plus a margin requirement. Receivables from contracts with our members at December 31, ~~2020, 2019~~2023, 2022 and ~~2018~~2021 were ~~$135,462,000, $142,946,000~~$170,901,000, $187,401,000 and ~~$122,888,000,~~$143,715,000, respectively. Payment is typically received the following month in which capacity and energy are billed. Estimated energy charges are billed based on the amount of energy supplied during the month and are adjusted when actual costs are available, generally the following month.

The remainder of our receivables is primarily related to transactions with non-members from the sale of the BC Smith deferring members' output, affiliated companies and investment income. Our receivables from non-members at December 31, 2023 and 2022 were $30,883,000 and $32,614,000, respectively. Our receivables from non-members were insignificant at December 31, 2021.

As a result of our historical experience, the short duration lifetime of our receivables and the short time horizon over which to consider expectations of future economic conditions, we have assessed that non-collection of the cost basis of our receivables is remote. During ~~2020, 2019~~2023, 2022 and ~~2018, 0~~2021, no credit losses were recognized on any receivables that arose from contracts with members or non-members.

The cost of nuclear fuel is amortized to fuel expense based on usage. The total nuclear fuel expense for ~~2020, 2019~~2023, 2022 and ~~2018~~2021 amounted to ~~$75,968,000, $79,893,000,~~$84,192,000, $73,871,000, and ~~$85,949,000,~~$77,366,000, respectively.

Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants has pursued and continues to pursue legal remedies against the Department of Energy for breach of contract.

Both Plants Hatch and Vogtle have on-site dry spent storage facilities in operation. ~~Facilities~~We expect that facilities at both plants can be expanded to accommodate spent fuel through the expected life of each plant.

Asset retirement obligations are legal obligations associated with the retirement of long-lived assets. These obligations represent the present value of the estimated costs for an asset's future retirement discounted using a credit-adjusted risk-free rate, and are recorded in the period in which the liability is incurred. The liabilities we have recognized primarily relate to the decommissioning of our nuclear facilities and coal ash ponds. In addition, we have retirement obligations related to gypsum cells, powder activated carbon cells, landfill sites and asbestos removal. Under the accounting provision for regulated

Periodically, we obtain revised cost studies associated with our nuclear and fossil plants' asset retirement obligations. Actual retirement costs may vary from these estimates. The estimated costs of nuclear and coal ash pond decommissioning are based on the most recent studies performed in ~~2018~~2020, 2021 and ~~2019,~~2023, respectively.

We apply the provision of regulated operations to nuclear decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses) of our nuclear decommissioning funds are compared to the associated decommissioning expenses with the difference deferred as regulatory asset or liability. As this difference is largely attributable to the timing of decommissioning fund earnings, the difference is recorded as an adjustment to investment income in our consolidated statements of revenues and expenses. Unrealized gains and losses of the decommissioning funds are recorded directly to the regulatory asset or liability for asset retirement obligations in accordance with our ratemaking treatment.

We have internally segregated the funds collected for coal ash pond and ~~landfill~~other CCR decommissioning costs, including earnings thereon. As of December 31, ~~2020~~2023 and December 31, ~~2019~~2022, the fund balances were ~~$120,536,000~~$176,630,000 and ~~$93,184,000,~~$153,208,000, respectively.

We apply the provision of regulated operations to coal ash pond and ~~landfill~~other CCR decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses) are compared to the associated decommissioning expenses with the difference deferred to or amortized from the regulatory asset. This difference is recorded to the associated expenses in our consolidated statements of revenues and expenses. Unrealized gains and losses of the associated decommissioning fund are recorded directly to the regulatory asset in accordance with our ratemaking treatment.

Accounting standards for asset retirement and environmental obligations do not apply to a retirement cost for which there is no legal obligation to retire the asset, and non-regulated entities are not allowed to accrue for such future retirement costs. We continue to recognize retirement costs for these other obligations in our depreciation rates under the accounting provisions for regulated operations. Accordingly, the accumulated retirement costs for other obligations are reflected as a regulatory liability in our balance sheets. For information regarding accumulated retirement costs for other obligations, see Note 1q.

The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. The NRC definition of decommissioning does not include all costs that may be associated with decommissioning, such as spent fuel management and non-radiated structures. We have established external trust funds to comply with the NRC's regulations. Upon approval by the NRC, any funding in the external trust in excess of their requirements may be used for other decommissioning costs. ~~In 2020~~As a result of nuclear fuel load for Plant Vogtle Units No. 3 and ~~2019, 0 additional amounts were~~No. 4, in 2023 and 2022, we contributed $4,619,000 and $2,643,000, respectively, to the external trust funds. These funds are managed by unrelated third party investment managers with the discretion to buy, sell and invest pursuant to investment objectives and restrictions set forth in agreements entered into between us and the investment managers. We record the investment securities held in the nuclear decommissioning trust fund at fair value, as disclosed in Note 2. Because day-to-day investment decisions are made by third party investment managers, the ability to hold investments in unrealized loss positions is outside our control.

In addition to the external trust funds, we maintain unrestricted investments internally designated for nuclear decommissioning. These internal funds are available to be utilized to fund the external trust funds, should additional funding be required, as well as other decommissioning costs outside the scope of the NRC funding regulations. The funds are included in long-term investments on our consolidated balance ~~sheet. In both 2020~~sheets. We contributed $10,000,000 and ~~2019, we contributed $4,750,000~~$8,350,000 into the internal ~~funds.~~funds in 2023 and 2022, respectively.

The following table outlines the fair value of our nuclear decommissioning funds as of December 31, ~~2020~~2023 and December 31, ~~2019.~~2022. The funds were invested in a diversified mix of approximately ~~64%~~71% equity and ~~36%~~29% fixed income securities in ~~2020~~2023 and ~~2019.~~69% equity and 31% fixed income securities in 2022.

Realized and unrealized gains and losses of the nuclear decommissioning funds that would be recorded in earnings by a non-regulated entity are directly deducted from or added to the regulatory asset or liability for asset retirement obligations in accordance with our rate-making treatment.

The nuclear decommissioning trust fund has produced an average annualized return of approximately ~~8.4%~~6.2% in the last ten years and ~~6.9%~~6.0% since inception in 1990. Based on current funding and cost study estimates, we expect the current balances and anticipated investment earnings of our decommissioning fund assets to be sufficient to meet all of our future nuclear decommissioning costs. Notwithstanding the above assumption, our management believes that increases in cost estimates of decommissioning can be recovered in future rates.

Electric plant is stated at original cost, which is the cost of the plant when first dedicated to public service, including acquisition adjustments, if any, plus the cost of any subsequent additions. Cost includes an allowance for the cost of equity and debt funds used during construction and allocable overheads. For the years ~~2020, 2019~~2023, 2022 and ~~2018,~~2021, the allowance for funds used during construction rates were ~~4.00%~~4.18%, ~~4.30%~~4.03% and ~~4.25%~~3.90%, respectively.

Replacements and renewals of items considered to be units of property, the lowest level of property for which we capitalize, are charged to the plant accounts. At the time properties are disposed of, the original cost is charged to the accumulated provision for depreciation. Cost of removal, less salvage, is charged to a regulatory liability, accumulated retirement costs for other assets. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are charged to expense, including certain major maintenance costs at our natural gas-fired plants.

We consider all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents. Temporary cash investments with maturities at the time of purchase of more than three months are classified as short-term investments.

Restricted cash consists of collateral posted by our counterparties under our natural gas swap agreements. The following table provides a reconciliation of cash, cash equivalents and ~~2019, we had~~ restricted ~~investments totaling $487,587,000 and $533,590,000, respectively,~~cash reported within the consolidated balance sheets that sum to the total of ~~which $306,601,000 and $461,757,000, respectively, were classified as long-term.~~the same such amounts reported in the consolidated statements of cash flows.

We maintain inventories of fossil fuel and spare parts, including materials and supplies for our generation plants. These inventories are stated at weighted average cost.

The fossil fuel inventories primarily include the direct cost of coal and related transportation charges. The cost of fossil fuel inventories is carried at weighted average cost and is charged to fuel expense as consumed. The spare parts inventories primarily include the direct cost of generating plant spare parts. The spare parts inventory is carried at weighted average cost and the parts are charged to expense or capitalized, as appropriate when installed.

At December 31, ~~2020~~2023 and December 31, ~~2019,~~2022, fossil fuels inventories were ~~$83,547,000~~$74,149,000 and ~~$74,257,000,~~$64,386,000, respectively. Inventories for spare parts at ~~2020~~2023 and ~~2019~~2022 were ~~$196,742,000~~$262,896,000 and ~~$203,472,000,~~$233,565,000, respectively.

~~Other deferred~~Deferred charges ~~primarily~~and other assets represent ~~advance deposits~~regulatory assets, long-term prepayments to Georgia Power Company ~~related to the Vogtle construction project~~ and ~~future generation project costs.~~

We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills monthly and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through December ~~2024,~~2028, with the majority of the balance scheduled to be credited by the end of ~~2023.~~2025.

Deferred credits and other liabilities also consists of asset retirement obligations as discussed in Note 1h and regulatory liabilities in Note 1q.

We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates established under the wholesale power contracts we have with

We and our 38 members are members of Georgia Transmission. Georgia Transmission provides transmission services to its members for delivery of its members' power purchases from us and other power suppliers. We have entered into an agreement with Georgia Transmission to provide transmission services for third party transactions and for service to our owned facilities. For ~~2020, 2019,~~2023, 2022, and ~~2018,~~2021, we incurred expenses from Georgia Transmission of ~~$37,931,000, $37,156,000~~$41,426,000, $40,774,000 and ~~$30,428,000,~~$39,677,000, respectively.

We, Georgia Transmission and 38 of our members are members of Georgia ~~Systems~~System Operations. Georgia ~~Systems~~System Operations operates the system control center and currently provides us system operations services and administrative support services. For ~~2020, 2019,~~2023, 2022, and ~~2018,~~2021, we incurred expenses from Georgia ~~Systems~~System Operations of ~~$27,104,000, $26,730,000,~~$30,109,000, $27,416,000, and ~~$25,578,000,~~$26,936,000, respectively.

Other income includes net revenue from Georgia Transmission and Georgia ~~Systems~~System Operations for administrative costs, as well as capital credits from investments in associated organizations and other miscellaneous income. In 2021, other income increased due to the recognition of gains on the sale of spare inventory parts from one of our generating facilities.

Authoritative guidance regarding fair value measurements for financial and non-financial assets and liabilities defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and expands disclosures about fair value measurements.

The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows:

Assets and liabilities measured at fair value are based on one or more of the following three valuation techniques:

The Level 2 investments above in corporate bonds and debt, federal agency mortgage backed securities, and mortgage backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are 0no unfunded commitments for the international equity trust and redemption may occur daily with a 3-day redemption notice period.

The Level 3 investments above in corporate bonds and debt consist of investments in bank loans which are not exchange traded. Although these securities may be liquid and priced daily, their inputs are not observable.

We use commodity ~~trading~~ derivatives to manage our exposure to fluctuation in the market price of natural gas. Our risk management and compliance committee provides general oversight over all derivative activities. We do not apply hedge accounting to derivative transactions, but instead apply regulated operations accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps are reflected as regulatory assets or liabilities, as appropriate. Realized gains and losses on natural gas swaps are included in fuel expense within our consolidated statements of revenues and expenses and, therefore, net margins within our consolidated statements of cash flows.

We are exposed to credit risk as a result of entering into these ~~hedging~~ arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions.

It is possible that volatility in commodity prices could cause us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of December 31, ~~2020~~2023 all of the counterparties with transaction amounts outstanding under our ~~hedging~~derivative programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.

We have entered into International Swaps and Derivatives Association agreements with our natural gas ~~hedge~~derivative counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement).

Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring certain of our counterparties' credit standing and condition. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions.

The contractual agreements contain provisions that could require us or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party's credit ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.

Under the natural gas swap arrangements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment.

At December 31, ~~2020~~2023 and ~~2019,~~2022, the estimated fair ~~value~~values of our natural gas contracts ~~was a~~were net ~~liability~~assets of ~~$10,248,000~~$13,445,000 and ~~$32,256,000,~~$131,804,000, respectively.

CT Parts, LLC is an affiliated organization formed by us and Smarr EMC for the purpose of purchasing and maintaining spare parts inventory and for the administration of contracted services for combustion turbine generation facilities. Such investment is recorded at cost.

In December 1996 and January 1997, we entered into 6six long-term lease transactions relating to our 74.61% undivided interest in Rocky Mountain. In each transaction, we leased a portion of our undivided interest in Rocky Mountain to 6six separate owner trusts for the benefit of 3three investors, referred to as owner participants, for a term equal to 120% of the estimated useful life of Rocky Mountain. Immediately thereafter, the owner trusts leased their undivided interests in Rocky Mountain to our wholly owned subsidiary, Rocky Mountain Leasing Corporation, or RMLC, for a term of 30 years under 6six separate leases. RMLC then subleased the undivided interests back to us under 6six separate leases for an identical term.

In 2012, we terminated 5five of the 6six lease transactions prior to the end of their lease terms. The remaining lease in place represented approximately 10% of the original lease transactions. Pursuant to a payment undertaking agreement, we have a guarantee for the annual basic rent payments due under the remaining lease. The fair value amount relating to the guarantee of basic rent payment is immaterial to us principally due to the high credit rating of the payment undertaker, Rabobank Nederland. The basic rental payments remaining through the end of the lease, which expires in 2027, are approximately ~~$30,892,000.~~$13,901,000.

At the end of the term of the remaining facility lease, we have the option to cause RMLC to purchase the owner trust's undivided interest in Rocky Mountain at a fixed purchase option price of approximately $112,000,000. The payment undertaking agreement, along with the equity funding agreement with AIG Matched Funding Corp., would fund approximately $74,000,000 and $37,928,000 of this amount, respectively, and these amounts would be paid to the owner trust over 5five installments in 2027. If we do not elect to cause RMLC to purchase the owner trust's undivided interest in Rocky Mountain, Georgia Power has an option to purchase the undivided interest. If neither we nor Georgia Power exercise our

Under the first two of these options we must arrange new financing for the outstanding amount of the loan used to finance the owner trust's upfront rental payment made to us when the lease closed on December 31, 1996. At the end of the lease term, the amount of the outstanding loan is anticipated to be approximately $74,000,000. If new financing cannot be arranged, the owner trust can ultimately cause us to purchase 49%, in the case of the first option above, or all, in the case of the second option above, of the loan certificate or cause RMLC to exercise its purchase option or RMLC to renew the facility lease and facility sublease, respectively.

We file a U.S. federal consolidated income tax return. The U.S. federal statute of limitations remains open for the year ~~2017~~2020 and forward. State jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state jurisdictions include ~~2017~~2020 and forward. We have no liabilities recorded for uncertain tax positions.

Long-term debt consists of first mortgage notes payable to the United States of America acting through the Federal Financing Bank (FFB) and guaranteed by the Rural Utilities Service or the U.S. Department of Energy, first mortgage bonds payable (FMBs) and first mortgage notes issued in conjunction with the sale by public authorities of pollution control revenue bonds ~~(PCBs)~~(PCRBs). Substantially all of our owned tangible and certain of our intangible assets are pledged under our first mortgage indenture as collateral for the Federal Financing Bank notes, the first mortgage bonds, and the first mortgage notes issued in conjunction with the sale of pollution control revenue bonds.

The weighted average interest rate on our long-term debt at December 31, ~~2020~~2023 and ~~2019~~2022 was ~~3.73%~~3.89% and ~~3.96%~~3.78%, respectively. The weighted average interest rate on our short-term borrowings at December 31, 2023 and 2022 was 5.72% and 4.84%, respectively.

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations under a Note Purchase Agreement, dated as of February 20, 2014 (the Original Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and 2two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB Documents).

On March 22, 2019, we and the Department of Energy entered into an Amended and Restated Loan Guarantee Agreement (as amended, the Loan Guarantee Agreement) which increased the aggregate amount guaranteed by the Department of Energy to $4,676,749,167. We also entered into a Note Purchase Agreement dated as of March 22, 2019 (the Additional Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and a future advance promissory note, dated March 22, 2019, made by us to the Federal Financing Bank in the amount of $1,619,679,706 (the Additional FFB Note and together with the Additional Note Purchase Agreement, the Additional FFB Documents).

During ~~2020,~~2023, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling ~~$45,925,000~~$70,272,000 for long-term financing of general and environmental improvements at existing ~~plants.~~

In ~~January 2021,~~February 2024, we received an additional ~~$238,578,000~~$6,067,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants.

On ~~August 25, 2020,~~December 5, 2023, we issued ~~$450,000,000~~$400,000,000 of ~~3.75%~~6.20% first mortgage bonds, Series ~~2020A~~2023A, for the purpose of providing long-term financing for expenditures related to the construction of Vogtle Units No. 3 and No. 4. In conjunction with the issuance of the bonds, we repaid ~~$439,200,000~~$390,612,000 of outstanding commercial paper. The bonds are due to mature ~~August 2050~~December 2053 and are secured under our first mortgage indenture.

We, along with Georgia Power, have entered into agreements providing for the purchase and subsequent joint operation of certain electric generating plants. Each co-owner is responsible for providing their own financing. The plant investments

Our proportionate share of direct expenses of joint operation of the above plants is included in the corresponding operating expense captions (e.g., fuel, production) on the accompanying ~~Statement~~consolidated statements of ~~Revenues~~revenues and ~~Expenses.~~expenses.

In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (collectively, Westinghouse). Pursuant to the EPC Agreement, Westinghouse agreed to design, engineer, procure, construct and test 2two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle.

Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Effective in July 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement (the Services Agreement), pursuant to which Westinghouse is providing facility design and engineering services, procurement and technical support and staff augmentation on a time and materials cost basis. The Services Agreement provides that it will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. ~~The Services Agreement is terminable by the Co-owners upon 30 days' written notice.~~

In October 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, pursuant to which Bechtel serves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement)~~. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel~~ and is reimbursed for actual costs plus a base fee and an at-risk fee, ~~which is~~ subject to adjustment based on ~~Bechtel's~~Bechtel’s performance against cost and schedule targets. Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion

On July 31, 2023, Georgia Power placed Unit No. 3 in service.

In connection with the September 2018 vote to continue construction, Georgia Power entered into a binding term sheet with the other Co-owners and MEAG’s wholly-owned subsidiaries MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, and MEAG Power SPVP, LLC to mitigate certain financial exposure for the other Co-owners and offered to purchase production tax credits from each of the other Co-Owners, at that Co-owner’s option (the Term Sheet). In February 2019, the Co-owners entered into the Global Amendments to memorialize the provisions of the Term Sheet. Pursuant to the Global Amendments and consistent with the Term Sheet, the Joint Ownership Agreements provide that:

The ultimate outcome of these matters cannot be determined at this time.

Our retirement plan is a contributory 401(k) that covers substantially all employees. An employee may contribute, subject to IRS limitations, up to 60% of his or her eligible annual compensation. At our discretion, we may match the employee's contribution and have done so each year of the plan's existence. The match, which is calculated each pay period,

Our 401(k) plan also includes an employer retirement contribution feature, which subject to IRS limitations, contributes 11% of an employee's eligible annual compensation. Our contributions to the employer retirement contribution feature of the 401(k) plan were approximately ~~$4,371,000, $4,172,000~~$5,655,000, $5,098,000 and ~~$3,903,000~~$4,527,000 in ~~2020, 2019~~2023, 2022 and ~~2018,~~2021, respectively.

We also sponsor 2two deferred compensation plans for eligible employees. Eligible employees are defined as highly compensated individuals within the definition of the Internal Revenue Code. The plans offer investment options to all eligible participants without regard to salary limits. In addition, one plan enables us to continue employer retirement contributions to highly compensated employees who exceed Internal Revenue Code salary limits for retirement plan contributions. The value of the plans is recorded as an asset and an equal offsetting liability with balances of ~~$4,716,000~~$5,723,000 and ~~$3,440,000~~$4,616,000 in ~~2020~~2023 and ~~2019,~~2022, respectively.

The Price-Anderson Act limits public liability claims that could arise from a single nuclear incident to ~~$13.8~~$16.2 billion. This amount is covered by private insurance and a mandatory program of deferred premiums that could be assessed against all owners of nuclear power reactors. Such private insurance provided by American Nuclear Insurers (ANI), is carried by Georgia Power for the benefit of all the co-owners of Plants Hatch and Vogtle. Agreements of indemnity have been entered into by and between each of the co-owners and the NRC. In the event of a nuclear incident involving any commercial nuclear facility in the country involving total public liability in excess of $450 million, a licensee of a nuclear power plant could be assessed a deferred premium of up to ~~$138~~$166 million per incident for each licensed reactor operated by it, but not more than ~~$20~~$25 million per reactor per incident to be paid in a calendar year. On the basis of our ownership interest in 4six nuclear reactors, we could be assessed a maximum of ~~$165~~$299 million per incident, but not more than ~~$25~~$44 million in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every 5 years, and exclude any applicable state premium taxes. The next scheduled adjustment is due no later than November 1, ~~2023.~~2028.

Georgia Power, on behalf of all the co-owners of Plants Hatch and Vogtle, is a member of Nuclear Electric Insurance, Ltd. (NEIL), a mutual insurer established to provide property damage insurance coverage in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, there is coverage through NEIL for decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses and policies providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage.

NEIL also covers the additional costs that could be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted. We started purchasing this coverage in April 2023.

Georgia Power, on behalf of all the co-owners has purchased a builders' risk property insurance policy from NEIL for Vogtle Units No. ~~3 and No.~~ 4. This policy provides the Vogtle owners up to $2.75 billion in limits for accidental property damage occurring during construction.

Under each of the NEIL policies, members are subject to retroactive assessments in proportion to their premiums, if losses each year exceed the accumulated reserve funds available to the insurer. The ~~portion of the current~~ maximum annual assessment for ~~Georgia Power that would be payable by~~ Oglethorpe based on ownership share, is limited to approximately ~~$42~~$55 million.

Claims resulting from terrorist acts and cyber events are covered under both the ANI and NEIL policies (subject to normal policy limits). The maximum aggregate ~~however,~~ that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. The maximum aggregate that NEIL will pay for all claims resulting from cyber acts and cyber events in any 12-month period is $3.2 billion each, plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.

For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are next to be applied toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to Georgia Power, for the benefit of all the co-owners, or to bond trustees as may be appropriate under the policies and applicable trust indentures.

All retrospective assessments, whether generated for liability or property, may be subject to applicable state premium taxes. In the event of a loss, the amount of insurance available may not be adequate to cover property damage and other incurred expenses. Uninsured losses and other expenses could have a material adverse effect on our financial condition and results of operations.

We have entered into long-term commitments to meet fuel, transportation, maintenance and asset retirement requirements.

To supply a portion of the fuel requirements to our co-owned generating units, Georgia Power, on our behalf for coal and Southern Nuclear on our behalf for nuclear fuel, have entered into various long-term commitments for the procurement of coal and nuclear fuel. The contracts in most cases contain provision for price escalations, minimum and maximum purchase levels and other financial commitments. The value of the coal commitments is based on maximum coal prices and minimum volumes as provided in the contracts and does not include taxes, transportation, government impositions or railcar costs.

We have entered into long-term agreements with various counterparties to provide firm natural gas transportation to our natural gas-fired facilities. The value of these agreements is based on fixed rates as provided in the contracts and does not include variable costs.

We have also entered into long-term maintenance agreements for certain of our natural gas-fired facilities. In most cases, these agreements include provisions for price escalation and performance bonuses and, if applicable, are included in the values; timing of expenditures is based on current operational assumptions. Certain agreements contain significant cancellation for convenience penalties and, therefore, amounts in the table below include total estimated expenditures over the life of the agreement. If these agreements were terminated by us in ~~2021~~2024 for convenience, our cancellation obligation would be approximately ~~$54,007,000.~~$70,699,000.

We have asset retirement obligations which are legal obligations to retire long-lived assets. These obligations are primarily for the decommissioning of our nuclear units and coal ash ponds. Expenditures are based on estimates determined through decommissioning studies and include provisions for price escalation and other factors. See Note 1h for information regarding our asset retirement obligations.

We have a small portfolio of leases with the most significant being a finance lease for our 60% undivided interest in Scherer Unit No. 2. In addition, we have other operating leases including railcar leases for the transportation of coal at our coal-fired ~~plants~~plant and various other leases of minimal value. For information regarding these leases, see Note 6.

We do not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined.

As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We ~~are~~may also become subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide.

Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance.

None.

Our management has prepared this annual report on Form 10-K and is responsible for the financial statements and related information included herein. These statements were prepared in accordance with generally accepted accounting principles and necessarily include amounts that are based on best estimates and judgments of management. Financial information throughout this annual report on Form 10-K is consistent with the financial statements.

Management believes that our policies and procedures provide reasonable assurance that our operations are conducted with a high standard of business ethics. In management's opinion, our financial statements present fairly, in all material respects, our financial position, results of operations, and cash flows.

Under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Exchange Act. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, ~~2020~~2023 in providing a reasonable level of assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information we are required to disclose in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013 framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Based on this evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, ~~2020~~2023 in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

There were no changes in our internal control over financial reporting that occurred during the fourth quarter ended December 31, ~~2020,~~2023, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

~~None.~~During the fiscal quarter ended December 31, 2023, none of our directors or “officers,” as defined in Rule 16a-1(f) under the Securities Exchange Act of 1934, adopted or terminated any “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as those terms are defined in Item 408 of Regulation S-K. As noted on the cover page of this annual report, we are a membership corporation and have no authorized or outstanding equity securities although we do have outstanding debt securities.

Not applicable.

Our members elect our board of directors. Our board of directors consists of directors and general managers from our members, referred to as "member directors," and up to two outside directors. Our bylaws divide member director positions among the member scheduling groups specifically described in the bylaws, referred to as the "member groups." There are currently five member groups and, except for Group 5, each member group is represented by two member directors. Of each member group's two directors, one must be a general manager of a member in that member group and one must be a director of a member in that member group. Jackson Electric Membership Corporation is the only member in Group 5 and has only one director. The bylaws permit expansion of the number of member groups and changes in the composition of member groups. Formation of new member groups and changes in the composition of member groups are subject to certain required member approvals, and the requirement that the composition of the member groups at Oglethorpe, Georgia Transmission and Georgia System Operations be identical, except in cases where a member is no longer a member of one or more of Oglethorpe, Georgia Transmission or Georgia System Operations. The number of member director positions will change if additional member groups are formed or a member group ceases to exist. The bylaws also provide for three at-large member director positions which may only be filled by a director of one of our members.

In an effort to provide for equitable representation among the member groups across the boards of directors of Oglethorpe, Georgia Transmission and Georgia System Operations, the bylaws provide for certain limitations on the eligibility of directors of members of each member group to fill the three at-large member director positions. No more than one at-large member director position on our board of directors may be filled by a director of a member of any member group, no more than two directors from members of any member group may be serving in at-large member director positions on the boards of directors of Oglethorpe, Georgia Transmission and Georgia System Operations, and at least one at-large member director position on the boards of directors of Oglethorpe, Georgia Transmission or Georgia System Operations must be filled by a director of a member of each member group that has at least two members.

Pursuant to the bylaws, a member may not have both its general manager and one of its directors serve as a director of ours at the same time. Subject to a limited exception for Jackson Electric Membership Corporation, which is the sole member of one of the member groups, the bylaws prohibit any person from simultaneously serving as a director of Oglethorpe and either Georgia Transmission or Georgia System Operations.

Our bylaws require outside directors to have experience related to our business, including, without limitation, operations, marketing, finance or legal matters. No outside director may be one of our current or former officers, a current employee of ours or a former employee of ours receiving compensation for prior services. Outside directors cannot also be a director, officer or employee of Georgia Transmission, Georgia System Operations or any member. Additionally, no person who receives payment from us in any capacity other than as an outside director, including direct or indirect payments for goods and services, may serve as outside director.

The members of our board of directors serve staggered three-year terms.

For a cooperative organization to maintain its status under federal tax law, it must abide by the cooperative principle of democratic control. The nomination and election of the members of our board of directors and the representation of our members by the elected directors is consistent with this principle.

Candidates for our board of directors must be nominated by the nominating committee. The nominating committee is comprised of one representative from each of our members. A majority vote of the nominating committee is required to

Neither we, the nominating committee, nor any of our members, to our knowledge, have a policy with regard to the consideration of diversity in identifying potential candidates for our board of directors.

Our principal executive officer and chairman of the board positions are separate and are held by different persons. The chairman of the board and any vice-chairman of the board are elected annually by a majority vote of the members of our board of directors. Our president and chief executive officer is appointed by our board of directors. None of our executive officers or other employees are members of our board of directors.

As a cooperative, our members are our owners. Our members believe that the most effective structure to efficiently provide for their current and future needs is to take a prominent role in the direction of our business. Member control over the board of directors, and the board of directors' independence from management is beneficial and provides for member input. Direct accountability to and separation from the board of directors helps ensure that management acts in the best interests of our members.

We are managed and operated under the direction of a president and chief executive officer who is appointed by our board of directors. Our president and chief executive officer selects the remainder of the executive officers. Certain of our executive officers have entered into an employment contract with us that provides for minimum annual base salary and performance pay. See "EXECUTIVE COMPENSATION – Compensation Discussion and Analysis – Employment Agreements" for further discussion of these agreements.

Our board of directors has established an audit committee, a compensation committee and a construction project committee. The audit committee, the compensation committee and the construction project committee each operate pursuant to a committee charter and/or policy. We do not have a nominating and corporate governance committee; directors are

Our board of directors and the audit committee both actively oversee our exposure to risks in our business. Our board of directors has adopted corporate policies regarding management of risks related to financial management, capital investment and the use of derivatives. One of the primary risk oversight activities of the board of directors is to hold an annual strategic planning session to review potentially material threats and opportunities to our business. To facilitate this review, management develops a comprehensive strategic issues matrix. The strategic issues matrix identifies, describes, assesses and classifies the potential impact or magnitude, and outlines corporate strategies for addressing potentially material threats and opportunities to our business. During this session, our board of directors reviews these analyses and affirms or assists management with developing strategies to address these strategic risks and opportunities. Additionally, management also develops and typically shares a corporate risk map with our audit committee. The corporate risk map depicts the probability of occurrence and the potential severity for each significant corporate risk.

At each regular meeting of the board of directors, management provides the board with reports on significant changes related to the top strategic risks and opportunities facing us and a revised version of the strategic issues matrix that highlights any revisions to the matrix. The audit committee chairman also provides the board of directors with updates on overall corporate risk exposure. Furthermore, the board of directors receives risk analysis reports that identify key risks that could create variances from our approved annual budget and long-range forecasts and discuss the potential likelihood and magnitude of changes to member rates related to these risks based on scenario modeling.

Our board of directors has delegated direct oversight of corporate risk management and compliance to the audit committee. Pursuant to its charter, the audit committee reviews our business risk management process, including the

We have adopted a Code of Conduct that applies to all our employees, including our principal executive, financial and accounting officers. Our Code of Conduct is available at our website, www.opc.com.

The philosophy and objective of our compensation and benefits program is to establish and maintain competitive total compensation programs that will attract, motivate and retain the qualified and skilled workforce necessary for our continued success. The compensation committee of the board of directors has the primary responsibility for establishing, implementing and monitoring adherence with our compensation programs. To help align executive officers' interests with those of our members, we have designed a significant portion of our cash compensation program as a pay for performance based system that rewards executive officers based on our success in achieving the corporate goals discussed below. To remain competitive, we review our total compensation program against generally available market data to gain a general understanding of current compensation practices.

The compensation committee determined that compensation packages for the fiscal year ended December 31, ~~2020~~2023 for our executive officers should be comprised of the following three primary components:

Since we are an electric cooperative, we do not have any stock and as a result do not have equity-based compensation programs.

Importantly, our executive officers cannot help us meet our goals and improve performance without the work of others. For this reason, the performance goals set at the corporate level are the same for both executive officers and non-executive employees.

We also provide retirement benefits that allow executive officers the opportunity to develop an investment strategy that best meets their retirement needs. We will contribute up to $0.75 of every dollar an executive officer contributes to his or her retirement plan, up to 6% of an executive officer's pay per period. In ~~2020,~~2023, we contributed an additional amount equal to 11% of an executive officer's pay per period. See "– Nonqualified Deferred Compensation" below for additional information regarding our contributions to our executive officers' retirement plans.

The compensation committee currently reviews and recommends to the board of directors for approval the compensation, including any bonus, for our president and chief executive officer. Some of the factors reviewed include the position's duties and responsibilities, the individual's job performance, experience, longevity of service and overall value provided for our members. Each year, the compensation committee reviews the employment agreement of our president and chief executive officer and makes a recommendation to our board of directors whether it should be extended.

The compensation committee operates pursuant to a statement of functions that sets forth the committee's objectives and responsibilities. The compensation committee's objective is to review and recommend to the board of directors for approval any changes to various compensation related matters, as well as any significant changes in benefits cost or level of benefits, for the members of the board of directors, the executive officers, and other employees. The compensation committee annually reviews its statement of functions and makes any necessary revisions to ensure its responsibilities are accurately stated.

Our president and chief executive officer, together with the other executive officers, identifies corporate performance objectives that are used to determine performance pay amounts. He and our vice president, human resources present these

We choose to tie performance compensation to selected corporate goals that most appropriately measure our achievement of our strategic objectives. For ~~2020,~~2023, our performance measures were divided into the following categories: (i) safety, (ii) operations, (iii) construction and project management, (iv) corporate compliance, (v) financial and (vi) quality. Targeted performance measures in these categories are designed to help us accomplish our corporate goals which will benefit our members, employees and promote responsible environmental stewardship.

For an executive officer to earn his or her maximum performance pay, 100% of the performance measures must be achieved. The performance measures are weighted to align with our current strategic focus. Goals are reviewed annually and may be adjusted in order to reflect any changes in our strategic focus. We also review and refine these goals annually and make adjustments as necessary to ensure that we are consistently stretching our expectations and performance. Although some performance measures may stay the same, the applicable threshold may become more difficult. ~~For example, in 2020, we adjusted some of the performance thresholds for our operations goals.~~ The following provides an overview of the purposes of each category of our corporate goals:

Performance pay earned by our executive officers is based on our success in achieving each of our corporate goals. Annually, our board of directors approves a weighted system for determining performance pay whereby we assign a percentage to each of the goals, as noted below. Based on the achievement of each performance metric, a percentage of the weighted goal is available as performance pay to our executive officers. Each performance metric has a minimum threshold level that must be achieved before any performance pay is earned. If the actual performance for that metric meets the applicable threshold, then a pre-determined percentage of the percentage pay for that metric will be awarded. The percentage awarded will increase up to a maximum of 100% of the weighted goal if the maximum performance level of the performance metric is achieved. Threshold and maximum levels are reviewed annually and generally reset as necessary to demand ever improving corporate performance. Meeting the applicable thresholds is not guaranteed and requires diligence and hard work. Exceptional performance is required to reach the maximum goals.

We have an employment agreement with Mr. Smith, ~~Mr. Price,~~ Ms. Higgins, Mr. Sorrick, Mr. Ussery and ~~Mr. Ussery.~~Ms. Bloodworth. We negotiated each of these employment agreements on an arms-length basis, and the compensation committee determined that the terms of each agreement are reasonable and necessary to ensure that these executive officers' goals are aligned with our members' interests and that each performs his or her respective role while acting in our members' best interests. We review these agreements on an annual basis. ~~We do not have an employment agreement with Mr. Messersmith.~~

Our employment agreement with Mr. Smith extends through December 31, ~~2023.~~2026. Mr. Smith's agreement will automatically renew pursuant to the corresponding provision of the agreement for successive one-year periods unless either party provides written notice not to renew the agreement twenty-four months before the expiration of any extended term. Each year, our board of directors makes an affirmative determination as to whether to provide such notice and no such notice has been provided. Mr. Smith's minimum annual base salary under his agreement is ~~$630,000,~~$956,970, and is subject to review and adjustment by our board of directors. Mr. Smith is eligible to participate in incentive compensation plans generally available to similarly situated employees and for an annual bonus determined by our board of directors at its sole discretion. Mr. Smith is also entitled to an automobile or an automobile allowance during the term of the agreement. Mr. Smith's employment agreement contains severance pay provisions.

We also have employment agreements with ~~Mr. Price,~~ Ms. Higgins, Mr. Sorrick, Mr. Ussery and ~~Mr. Ussery.~~Ms. Bloodworth. The current term of ~~each agreement~~Ms. Higgins', Mr. Sorrick's, Mr. Ussery's and Ms. Bloodworth's agreements extends through December 31, ~~2023~~2026 and will automatically renew for successive one-year periods unless either party provides written notice not to renew the agreement twenty-four months before the expiration of any extended term. Each year, our president and chief executive officer makes an affirmative determination as to whether to provide such notice, and no such notices have been provided.

Minimum annual base salaries under these agreements are ~~$445,100 for Mr. Price, $448,250~~$555,000 for Ms. Higgins, ~~and $348,400~~$520,000 for Mr. ~~Ussery.~~Sorrick, $422,000 for Mr. Ussery and $405,000 for Ms. Bloodworth. Salaries are subject to review and possible adjustment as determined by the president and chief executive officer. Each executive is also eligible to participate in incentive compensation plans generally available to similarly situated employees and for an annual bonus determined by the president and chief executive officer at his sole discretion. The employment agreements with ~~Mr. Price,~~ Ms. Higgins, ~~and~~Mr. Sorrick, Mr. Ussery and Ms. Bloodworth contain severance pay provisions.

Pursuant to their respective employment agreements, certain of our executive officers are entitled to severance payments and benefits in the event they are terminated not for cause or they resign for good reason.

In determining that the president and chief executive officer's employment agreement was appropriate and necessary, the compensation committee considered Mr. Smith's role and responsibility within Oglethorpe in relation to the total amount of severance pay he would receive upon the occurrence of a severance event. The committee also considered whether the amount Mr. Smith would receive upon severance was appropriate given his total annual compensation. Upon review, the compensation committee determined that a maximum amount of severance compensation equal to a maximum of two year's compensation, plus benefits as described below, was an appropriate amount of severance compensation for Mr. Smith. The compensation committee believes that entering into a severance agreement with our president and chief executive officer is

Pursuant to the terms of his employment agreement, Mr. Smith will be entitled to a lump-sum severance payment upon the occurrence of any of the following events: (1) we terminate his employment without cause; or (2) he resigns due to a demotion or material reduction of his position or responsibilities, a material reduction of his base salary, or a relocation of his principal office by more than 50 miles. The severance payment will equal Mr. Smith's then current base salary through the rest of the term of the agreement (with a minimum of one year's pay and a maximum of two years' pay), and is payable within 30 days of termination, subject to the provisions of Internal Revenue Code Section 409A. In addition, Mr. Smith will be entitled to outplacement services and an amount equal to his costs for medical and dental continuation coverage under COBRA, each for the longer of one year or the remaining term of the agreement. Severance is payable only if Mr. Smith signs a form releasing all claims against us. The maximum severance that would be payable to Mr. Smith in the circumstances described above is ~~$1,905,975.~~$2,277,646.

Our president and chief executive officer considered the total amount of compensation ~~Mr. Price,~~ Ms. Higgins, ~~and~~Mr. Sorrick, Mr. Ussery and Ms. Bloodworth would receive upon the occurrence of a severance event and determined that it was appropriate for these executive officers to receive severance compensation equal to a maximum of two years of his or her then current base salary, plus benefits as described below, because such agreements provide a measure of stability for both us and the executive officers. In addition, like our president and chief executive officer, these executive officers are not compensated using options or other forms of equity compensation that lead to significant wealth accumulation. Therefore, our president and chief executive officer believes such severance compensation is necessary to address competitive concerns and offset any potential risk our executive officers face in the course of their employment.

Pursuant to the terms of their employment agreements, ~~Mr. Price,~~ Ms. Higgins, ~~and~~Mr. Sorrick, Mr. Ussery and Ms. Bloodworth will each be entitled to a lump-sum severance payment if we terminate the executive without cause or if the executive resigns after a demotion or material reduction of his or her position or responsibilities, a reduction of his or her base salary, or a relocation of his or her principal office by more than 50 miles. The severance payment will equal the executive officer's then current base salary through the rest of the term of the agreement (with a minimum of one year's pay and a maximum of two years' pay), payable within 30 days of termination, subject to the provisions of Internal Revenue Code Section 409A. In addition, the executive will be entitled to one year of outplacement services and an amount equal to the executive's cost for medical and dental continuation coverage under COBRA for one year. Severance is payable only if the executive signs a form releasing all claims against us. The maximum severance that would be payable to ~~Mr. Price,~~ Ms. Higgins, ~~and~~Mr. Sorrick, Mr. Ussery and Ms. Bloodworth in the circumstances described above is ~~$1,105,577, $1,107,570,~~$1,312,814, $1,216,914, $988,248 and ~~$839,192,~~$1,037,478, respectively.

The Compensation Committee of Oglethorpe Power Corporation has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussions, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the fiscal year ended December 31, ~~2020~~2023 for filing with the SEC.

Mr. Jakins, Mr. Bailey, Mr. ~~Jakins,~~McWhorter, Mr. Millwood, Mr. ~~McWhorter~~Nichols and Mr. ~~Nichols~~Weathersby served as members of our compensation committee during ~~2020.~~all or a portion of 2023.

Mr. Jakins is a director of ours and the President and Chief Executive Officer of Jackson Electric Membership Corporation. Jackson is a member of ours and has a wholesale power contract with us. Jackson's revenues of ~~$209.0~~$262.7 million to us in ~~2020~~2023 under its wholesale power contract accounted for approximately ~~15.2%~~15.1% of our total revenues.

Mr. Nichols is a director of ours and is the ~~General Manager~~President and Chief Executive Officer of Colquitt Electric Membership Corporation. Colquitt is a member of ours and has a wholesale power contract with us. Colquitt's revenues of ~~$41.4~~$42.8 million to us in ~~2020~~2023 under its wholesale power contract accounted for approximately ~~3.0%~~2.5% of our total revenues.

We maintain a Fidelity Non-Qualified Deferred Compensation Program for each of the executive officers in the table below. This non-qualified deferred compensation program serves as a vehicle through which we can continue our employer retirement contributions to our executive officers beyond the IRS salary limits on the retirement plan ($~~285,000~~330,000 as indexed).

We strive to provide fair and equitable compensation to each of our employees through a combination of competitive base pay, performance incentives, retirement plans and other benefits. The following pay ratio and supporting information compares the annual total compensation of Mr. Smith, our president and chief executive officer, to the annual total compensation of our median employee for the fiscal year ended December 31, ~~2020.~~2023.

To identify our median employee, we determined that as of December 31, ~~2020,~~2023, we had ~~299~~337 employees, including full-time, part-time, temporary and seasonal workers (excluding our president and chief executive officer), who were all located in the United States. We then calculated the annual total compensation for each of these employees for the fiscal year ended December 31, ~~2020~~2023 in the same manner in which we calculated our president and chief executive officer's total annual compensation presented in the "Summary Compensation Table." Employee compensation includes salary, performance pay and benefits.

Based upon this analysis, we determined that our median employee's annual total compensation for ~~2020~~2023 was ~~$152,601.~~$169,500. As set forth in the Summary Compensation Table, our president and chief executive officer's annual total compensation for ~~2020~~2023 was ~~$1,161,471.~~$1,546,661. The ratio of our president and chief executive officer's annual total compensation to our median employee's annual total compensation for the fiscal year ended December 31, ~~2020~~2023 was ~~7.61:~~9.12:1.

Not Applicable.

Randy Crenshaw is a director of ours and the President and Chief Executive Officer of Irwin Electric Membership ~~Corporation and Middle Georgia Electric Membership~~ Corporation. Irwin ~~and Middle Georgia are members~~is a member of ours and ~~each~~ has a wholesale power contract with us. Irwin's revenues of ~~$8.0~~$9.1 million to us in ~~2020~~2023 under its wholesale power contract accounted for approximately ~~0.6% of our total revenues. Middle Georgia's revenues of $5.1 million to us in 2020 under its wholesale power contract accounted for approximately 0.4%~~0.5% of our total revenues.

Chip Jakins is a director of ours and the President and Chief Executive Officer of Jackson Electric Membership Corporation. Jackson is a member of ours and has a wholesale power contract with us. Jackson's revenues of ~~$209.0~~$262.7 million to us in ~~2020~~2023 under its wholesale power contract accounted for approximately ~~15.2%~~15.1% of our total revenues.

Jeffrey Murphy is a director of ours and the President and Chief Executive Officer of Hart Electric Membership Corporation. Hart is a member of ours and has a wholesale power contract with us. Hart's revenues of ~~$18.0~~$23.9 million to us in ~~2020~~2023 under its wholesale power contract accounted for approximately ~~1.3%~~1.4% of our total revenues.

Danny Nichols is a director of ours and is the ~~General Manager~~President and Chief Executive Officer of Colquitt Electric Membership Corporation. Colquitt is a member of ours and has a wholesale power contract with us. Colquitt's revenues of ~~$41.4~~$42.8 million to us in ~~2020~~2023 under its wholesale power contract accounted for approximately ~~3.0%~~2.5% of our total revenues.

George Weaver is a director of ours and the President and Chief Executive Officer of Central Georgia Electric Membership Corporation. Central Georgia is a member of ours and has a wholesale power contract with us. Central Georgia's revenues of ~~$41.1~~$65.5 million to us in ~~2020~~2023 under its wholesale power contract accounted for approximately ~~3.0%~~3.8% of our total revenues.

We have a Standards of Conduct/Conflict of Interest policy that sets forth guidelines that our employees and directors must follow in order to avoid conflicts of interest, or any appearance of conflicts of interest, between an individual's personal interests and our interests. Pursuant to this policy, each employee and director must disclose any conflicts of interest, actions or relationships that might give rise to a conflict. Our president and chief executive officer is responsible for taking reasonable steps to ensure that the employees are complying with this policy and the audit committee is responsible for taking reasonable steps to ensure that the directors are complying with this policy. The audit committee is charged with monitoring compliance with this policy and making recommendations to the board of directors regarding this policy. Certain actions or relationships that might give rise to a conflict of interest are reviewed and approved by our board of directors.

In addition to meeting the requirements set forth in our bylaws, all directors, with the exception of Chip Jakins, satisfy the definition of director independence as prescribed by the NASDAQ Stock Market and otherwise meet the requirements set forth in our bylaws. Mr. Jakins does not qualify as an independent director because he is the President and Chief Executive Officer of Jackson Electric Membership Corporation, an organization from which we received more than 5% of our gross revenues for the fiscal year ended December 31, ~~2020.~~2023. Although we do not have any securities listed on the NASDAQ Stock Market, we have used its independence criteria in making this determination in accordance with applicable SEC rules.

In considering the nature of the services provided by our independent registered public accounting firm, the audit committee determined that such services are compatible with the provision of independent audit services. The audit committee discussed all non-audit services to be provided by independent registered public accounting firm to us with management prior to approving them to confirm that they were non-audit services permitted to be provided by our independent registered public accounting firm.

The audit and permissible non-audit services performed by Ernst & Young LLP in ~~2020~~2023 were pre-approved in accordance with the pre-approval policy and procedures adopted by the audit committee. The policy requires that requests for all services must be submitted to the audit committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre-approval is provided at regularly scheduled meetings.

None.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the ~~19th~~25th day of March, ~~2021.~~2024.


(Mark One)
☒			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

			For the fiscal year ended December 31, ~~2020~~2023

			OR

☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


Georgia			58-1211925
(State or other jurisdiction of incorporation or organization)			(I.R.S. employer identification no.)


2100 East Exchange Place Tucker, Georgia			30084-5336
(Address of principal executive offices)			(Zip Code)


Large accelerated filer ☐	Accelerated filer ☐	Non-accelerated filer ☒	Smaller reporting company ☐
			Emerging growth company ☐


ITEM		Page
	PART I
1	Business	1
	Oglethorpe Power Corporation	1
	Our Power Supply Resources	9
	Our Members and Their Power Supply Resources	16
	Regulation	20
1A	Risk Factors	26
1B	Unresolved Staff Comments	36
2	Properties	37
3	Legal Proceedings	42
4	Mine Safety Disclosures	42
	PART II
5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	43
6	Selected Financial Data	43
7	Management's Discussion and Analysis of Financial Condition and Results of Operations	45
7A	Quantitative and Qualitative Disclosures About Market Risk	61
8	Financial Statements and Supplementary Data	64
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	106
9A	Controls and Procedures	106
9B	Other Information	106
	PART III
10	Directors, Executive Officers and Corporate Governance	107
11	Executive Compensation	115
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	124
13	Certain Relationships and Related Transactions, and Director Independence	125
14	Principal Accountant Fees and Services	126
	PART IV
15	Exhibits and Financial Statement Schedules	127
	Signatures	143


Registrant's telephone number, including area code:			(770) 270-7600


Securities registered pursuant to Section 12(b) of the Act:			None


	(in millions)
	Project Budget		Actual Costs at December 31, 2020		Remaining Project Budget
Construction Costs (1)	$	5,559	$	4,754	$	805
Financing Costs	1,578		1,259		319
Total Costs	$	7,137	$	6,013	$	1,124

Project-Level Contingency	$	113	$	0	$	113
Oglethorpe-Level Contingency	250		0		250

Total Contingency	$	363	$	0	$	363
Totals	$	7,500	$	6,013	$	1,487

(1) Construction costs are net of $1.1 billion received from Toshiba Corporation under a Guarantee Settlement Agreement.


	Member Peak Demand (MW)(1)	Member Energy Requirements (MWh)
		Total(2)	Supplied by Oglethorpe(3)
2020	9,471	39,208,224	22,187,311
2019	9,476	40,385,813	23,255,861
2018	8,858	40,179,743	23,011,079


Facilities	Type of Fuel	Percentage Interest	Our Share of Nameplate Capacity (megawatts)	Commercial Operation Date	License Expiration Date
Plant Hatch (near Baxley, Ga.)
Unit No. 1	Nuclear	30	269.9	1975	2034
Unit No. 2	Nuclear	30	268.8	1979	2038

Plant Vogtle (near Waynesboro, Ga.)
Unit No. 1	Nuclear	30	348.0	1987	2047
Unit No. 2	Nuclear	30	348.0	1989	2049

Plant Wansley (near Carrollton, Ga.)
Unit No. 1	Coal	30	259.5	1976	N/A	(1)
Unit No. 2	Coal	30	259.5	1978	N/A	(1)
Combustion Turbine	Oil	30	14.8	1980	N/A	(1)

Plant Scherer (near Forsyth, Ga.)
Unit No. 1	Coal	60	490.8	1982	N/A	(1)
Unit No. 2	Coal	60	490.8	1984	N/A	(1)

Rocky Mountain (near Rome, Ga.)	Pumped Storage Hydro	74.61	632.5	1995	2026

Doyle (near Monroe, Ga.)	Gas	100	325.0	2000	N/A	(1)

Talbot (near Columbus, Ga.)
Units No. 1-4	Gas	100	412.0	2002	N/A	(1)
Units No. 5-6	Gas-Oil	100	206.0	2003	N/A	(1)

Chattahoochee (near Carrollton, Ga.)	Gas	100	468.0	2003	N/A	(1)

Hawk Road (near Franklin, Ga.)	Gas	100	500.0	2001	N/A	(1)

Hartwell (near Hartwell, Ga.)	Gas-Oil	100	300.0	1994	N/A	(1)

Smith (near Dalton, Ga.)
Unit No. 1	Gas	100	630.0	2002	N/A	(1)
Unit No. 2	Gas	100	620.0	2002	N/A	(1)


	Summer Planning Reserve Capacity(1) (Megawatts)	Equivalent Availability(2)						Capacity Factor(3)
Unit		2020		2019		2018		2020		2019		2018
Plant Hatch
Unit No. 1	262.2	83	%	98	%	91	%	83	%	99	%	91	%
Unit No. 2	264.3	97		82		95		97		82		96

Plant Vogtle
Unit No. 1	344.5	93		100		93		95		102		96
Unit No. 2	344.7	90		92		100		92		93		102

Plant Wansley
Unit No. 1	261.6	98		75		90		0		4		14
Unit No. 2	261.6	83		93		91		1		7		8
Combustion Turbine(4)	0	62		61		62		0		0		0

Plant Scherer
Unit No. 1	515.0	98		81		84		16		13		39
Unit No. 2	515.0	95		97		77		8		40		41

Rocky Mountain(5)
Unit No. 1	272.3	90		88		78		18		16		13
Unit No. 2	272.3	97		90		44		20		19		11
Unit No. 3	272.3	87		93		82		8		15		17

Doyle(5)	281.0	62		60		50		3		3		2

Talbot(5)	682.3	74		79		75		7		8		8

Chattahoochee	466.0	93		94		79		78		80		65

Hawk Road(5)	486.9	63		54		68		13		11		11

Hartwell(5)	305.5	81		84		75		6		13		6

Smith
Unit No. 1	658.6	82		75		43		59		53		29
Unit No. 2	658.6	86		81		90		66		61		67
TOTAL	7,124.7


	Nuclear				Coal-Fired				Pumped Storage
	Plant Hatch		Plant Vogtle(2)		Plant Wansley		Plant Scherer Units No. 1 & No. 2		Rocky Mountain		Total
	%	MW(1)	%	MW(1)	%	MW(1)	%	MW(1)	%	MW(1)	MW(1)
Oglethorpe	30.0	539	30.0	1,356	30.0	519	60.0	982	74.6	633	4,029
Georgia Power	50.1	900	45.7	2,066	53.5	926	8.4	137	25.4	215	4,244
MEAG	17.7	318	22.7	1,026	15.1	261	30.2	494	—	—	2,099
Dalton	2.2	39	1.6	72	1.4	24	1.4	23	—	—	158
Total	100.0	1,796	100.0	4,520	100.0	1,730	100.0	1,636	100.0	848	10,530


		(dollars in thousands)
		2020			2019			2018
	(dollars in thousands)																		(dollars in thousands)
	2023													2023			2022					2021
STATEMENTS OF REVENUES AND EXPENSES DATA	STATEMENTS OF REVENUES AND EXPENSES DATA
Operating revenues:	Operating revenues:
Sales to Members		$	1,377,010		$	1,429,852		$	1,479,379
Sales to non-Members		608			440			734
Operating revenues:
Operating revenues:
Sales to members
Sales to members
Sales to members
Sales to non-members
Operating expenses	Operating expenses	$	1,159,909		$	1,213,083		$	1,255,137
Other income, net	Other income, net	$	50,695		$	64,189		$	68,262
Net interest charges	Net interest charges	$	212,509		$	226,937		$	242,039
Net margin	Net margin	$	55,895		$	54,461		$	51,199

BALANCE SHEET DATA	BALANCE SHEET DATA
BALANCE SHEET DATA
BALANCE SHEET DATA
Assets:	Assets:
Assets:
Assets:
Total electric plant
Total electric plant
Total electric plant	Total electric plant	$	10,870,857		$	9,855,856		$	8,963,965
Total assets	Total assets	$	14,240,156		$	12,990,113		$	12,183,268
Capitalization:	Capitalization:
Patronage capital and membership fees	Patronage capital and membership fees	$	1,072,642		$	1,016,747		$	962,286
Patronage capital and membership fees
Patronage capital and membership fees
Long-term debt and obligations under finance leases	Long-term debt and obligations under finance leases	10,695,475			9,808,158			9,434,498
Obligation under Rocky Mountain transactions
Other	Other	26,861			25,196			21,428
Total long-term debt and equities	Total long-term debt and equities	$	11,794,978		$	10,850,101		$	10,418,212
Less: Long-term debt and finance leases due within one year	Less: Long-term debt and finance leases due within one year	208,649			217,440			522,289
Less: Unamortized debt issuance costs and bond discounts	Less: Unamortized debt issuance costs and bond discounts	119,565			111,222			103,331
Total capitalization	Total capitalization	$	11,466,764		$	10,521,439		$	9,792,592

OTHER DATA	OTHER DATA
Kilowatt hours sold to Members		22,187,311			23,225,861			23,011,079
OTHER DATA
OTHER DATA
Megawatt hours sold to members(1)
Megawatt hours sold to members(1)
Megawatt hours sold to members(1)
Member revenues per kWh sold	Member revenues per kWh sold	6.21 ¢			6.16 ¢			6.43 ¢			Member revenues per kWh sold	5.94 ¢			7.70 ¢					6.30 ¢
Equity Ratio(1)		9.1		%	9.4		%	9.2		%
Margins for Interest Ratio(2)		1.14			1.14			1.14
Equity Ratio(2)											Equity Ratio(2)	9.4	%		9.0	%				9.3	%
Margins for Interest Ratio(3)											Margins for Interest Ratio(3)	1.14						1.14


	(in thousands)									2023 vs. 2022		2022 vs. 2021
	2023			2022			2021			% Change		% Change
Capacity revenues	$	1,082,368		$	984,036		$	946,662		10.0	%	3.9	%
Energy revenues	599,198			990,647			610,447			(39.5)	%	62.3	%
Total	$	1,681,566		$	1,974,683		$	1,557,109		(14.8)	%	26.8	%

kWh Sales to members(1)	28,289,147			25,634,984			24,727,585			10.4	%	3.7	%
Cents/kWh	5.94			7.70			6.30			(22.8)	%	22.3	%
Member energy requirements supplied	68		%	58		%	62		%	17.2	%	(6.5)	%


	(in thousands)									2020 vs. 2019		2019 vs. 2018
	2020			2019			2018			% Change		% Change
Capacity revenues	$	971,071		$	942,057		$	927,419		3.1	%	1.6	%
Energy revenues	405,939			487,795			551,960			(16.8)	%	(11.6)	%
Total	$	1,377,010		$	1,429,852		$	1,479,379		(3.7)	%	(3.3)	%

kWh Sales	22,187,311			23,225,861			23,011,079			(4.5)	%	0.9	%
Cents/kWh	6.21			6.16			6.43			0.9	%	(4.2)	%
Member energy requirements supplied	57		%	58		%	57		%	(1.7)	%	1.8	%


	Cost										Generation							Cents per kWh
	(dollars in thousands)										(kWh in thousands)
Fuel Source	2023		2022		2021		2023 vs. 2022 % Change		2022 vs. 2021 % Change		2023	2022	2021	2023 vs. 2022 % Change		2022 vs. 2021 % Change		2023	2022	2021	2023 vs. 2022 % Change		2022 vs. 2021 % Change
Coal	$	124,638	$	107,207	$	86,289	16.3	%	24.2	%	3,166,368	2,856,494	2,559,235	10.8	%	11.6	%	3.94	3.75	3.37	4.9	%	11.3	%
Nuclear	84,192		73,871		77,366		14.0	%	(4.5)	%	11,122,301	10,206,060	10,171,948	9.0	%	0.3	%	0.76	0.72	0.76	4.6	%	(4.8)	%
Natural Gas:
Combined Cycle	323,614		704,809		387,069		(54.1)	%	82.1	%	14,804,306	13,100,271	12,722,401	13.0	%	3.0	%	2.19	5.38	3.04	(59.4)	%	76.8	%
Combustion Turbine	46,350		159,202		48,272		(70.9)	%	229.8	%	1,382,989	1,824,570	1,026,430	(24.2)	%	77.8	%	3.35	8.73	4.70	(61.6)	%	85.5	%
	$	578,794	$	1,045,089	$	598,996	(44.6)	%	74.5	%	30,475,964	27,987,395	26,480,014	8.9	%	5.7	%	1.90	3.73	2.26	(49.1)	%	65.1	%


	Cost										Generation							Cents per kWh
	(dollars in thousands)										(kWh in thousands)
Fuel Source	2020		2019		2018		2020 vs. 2019 % Change		2019 vs. 2018 % Change		2020	2019	2018	2020 vs. 2019 % Change		2019 vs. 2018 % Change		2020	2019	2018	2020 vs. 2019 % Change		2019 vs. 2018 % Change
Coal	$	40,222	$	80,706	$	119,459	(50.2)	%	(32.4)	%	1,137,027	2,592,023	4,062,982	(56.1)	%	(36.2)	%	3.54	3.11	2.94	13.6	%	5.9	%
Nuclear	75,968		79,893		85,949		(4.9)	%	(7.0)	%	9,832,564	10,061,609	10,314,928	(2.3)	%	(2.5)	%	0.77	0.79	0.83	(2.7)	%	(4.8)	%
Natural Gas:
Combined Cycle	202,030		225,816		240,122		(10.5)	%	(6.0)	%	10,473,139	9,649,561	8,047,494	8.5	%	19.9	%	1.93	2.34	2.98	(17.6)	%	(21.5)	%
Combustion Turbine	42,034		53,799		57,374		(21.9)	%	(6.2)	%	1,386,569	1,562,895	1,271,542	(11.3)	%	22.9	%	3.03	3.44	4.51	(11.9)	%	(23.7)	%
	$	360,254	$	440,214	$	502,904	(18.2)	%	(12.5)	%	22,829,299	23,866,088	23,696,946	(4.3)	%	0.7	%	1.58	1.84	2.12	(14.4)	%	(13.2)	%


Committed Credit Facilities
	(dollars in millions)
	Authorized Amount		Available 12/31/2023			Expiration Date
Unsecured Facilities:
Syndicated Line among 12 banks led by CFC	$	1,210	$	599	(1)	December 2024
CFC Line of Credit(2)	110		110			December 2028
JPMorgan Chase Line of Credit	350		347		(3)	October 2024
Secured Facilities:
CFC Term Loan(2)	250		140			December 2028


Capital Expenditures(1)	Capital Expenditures(1)									Capital Expenditures(1)
(dollars in millions)	(dollars in millions)									(dollars in millions)
		2021		2022		2023		Total			2024	2025	2026	Total
Future Generation(2)	Future Generation(2)	$	973	$	415	$	—	$	1,388
Existing Generation(3)	Existing Generation(3)	132		147		105		384
Environmental Compliance(4)	Environmental Compliance(4)	4		9		23		36
Nuclear Fuel(5)	Nuclear Fuel(5)	93		100		93		286
General Plant	General Plant	9		5		4		18
Total	Total	$	1,211	$	676	$	225	$	2,112


Committed Credit Facilities
	(dollars in millions)
	Authorized Amountd		Available 12/31/2020			Expiration Date
Unsecured Facilities:
Syndicated Line among 12 banks led by CFC	$	1,210	$	691	(1)	December 2024
CFC Line of Credit(2)	110		110			December 2023
JPMorgan Chase Line of Credit	363		247		(3)	October 2021
Secured Facilities:
CFC Term Loan(2)	250		140			December 2023


			Page
Consolidated Statements of Revenues and Expenses, For the Years Ended December 31, ~~2020, 2019~~202 3 , 202 2 and ~~2018~~202 1			6562
Consolidated Balance Sheets, at December 31, ~~2020~~202 3 and ~~2019~~202 2			6663
Consolidated Statements of Capitalization, at December 31, ~~2020~~202 3 and ~~2019~~202 2			6865
Consolidated Statements of Cash Flows, For the Years Ended December 31, ~~2020, 2019~~202 3 , 202 2 and ~~2018~~202 1			6966
Consolidated Statements of Patronage Capital and Membership Fees , For the Years Ended December 31, ~~2020, 2019,~~202 3 , 202 2 , and ~~2018~~202 1			7067
Notes to Consolidated Financial Statements			7168
Report of Independent Registered Public Accounting Firm (PCAOB ID: 42)			~~104~~103


	(dollars in thousands)
~~Balance at December 31, 2017~~	$	~~911,087~~
~~Components of comprehensive margin in 2018:~~
~~Net margin~~	~~51,199~~
~~Balance at December 31, 2018~~	$	~~962,286~~
~~Components of comprehensive margin in 2019:~~
~~Net margin~~	~~54,461~~
~~Balance at December 31, 2019~~	$	~~1,016,747~~
~~Components of comprehensive margin in 2020:~~
~~Net margin~~	~~55,895~~
Balance at December 31, 2020	$	1,072,642
Components of comprehensive margin in 2021:
Net margin	57,781
Balance at December 31, 2021	$	1,130,423
Components of comprehensive margin in 2022:
Net margin	61,704
Balance at December 31, 2022	$	1,192,127
Components of comprehensive margin in 2023:
Net margin	65,790
Balance at December 31, 2023	$	1,257,917


	(dollars in thousands)
	Nuclear		Coal Ash Pond		Other		Total
Balance at December 31, 2022	$	820,106	$	461,528	$	62,109	$	1,343,743
Liabilities incurred	62,841		—		—		62,841
Liabilities settled	—		(14,445)		(76)		(14,521)
Accretion	46,857		16,558		2,492		65,907
Deferred accretion	—		5		—		5
Change in cash flow estimates	—		321		641		962
Balance at December 31, 2023	$	929,804	$	463,967	$	65,166	$	1,458,937


	(dollars in thousands)
2021 site study	Hatch Unit No. 1		Hatch Unit No. 2		Vogtle Unit No. 1		Vogtle Unit No. 2
Expected start date of decommissioning	2034		2038		2047		2049
Estimated costs based on site study in 2021 dollars:
Radiated structures	$	227,000	$	236,000	$	200,000	$	213,000
Spent fuel management	60,000		51,000		58,000		53,000
Non-radiated structures	15,000		21,000		24,000		31,000
Total estimated site study costs	$	302,000	$	308,000	$	282,000	$	297,000


	(dollars in thousands)
2018 site study	Hatch Unit No. 1		Hatch Unit No. 2		Vogtle Unit No. 1		Vogtle Unit No. 2
Expected start date of decommissioning	2034		2038		2047		2049
Estimated costs based on site study in 2018 dollars:
Radiated structures	$	209,000	$	231,000	$	188,000	$	206,000
Spent fuel management	54,000		49,000		55,000		51,000
Non-radiated structures	14,000		19,000		23,000		29,000
Total estimated site study costs	$	277,000	$	299,000	$	266,000	$	286,000


	(dollars in thousands)
2020 site study	Vogtle Unit No. 3
Expected start date of decommissioning	2061
Estimated costs based on site study in 2020 dollars:
Radiated structures	$	187,000
Spent fuel management	19,000
Non-radiated structures	22,000
Total estimated site study costs	$	228,000


	2020
External Trust Funds:	(dollars in thousands)
	Cost 12/31/2019		Purchases		Net Proceeds(1)		Unrealized Gain(Loss)		Fair Value 12/31/2020
Equity	$	212,585	$	27,707	$	(16,444)	$	177,866	$	401,714
Debt	174,645		536,147		(523,926)		11,100		197,966
Other	(702)		14,756		(15,553)		0		(1,499)
	$	386,528	$	578,610	$	(555,923)	$	188,966	$	598,181


		2020
Internal Funds:		(dollars in thousands)
		Cost 12/31/2019		Purchases		Net Proceeds(1)		Unrealized Gain(Loss)		Fair Value 12/31/2020
	2023																2023
External Trust Funds:												External Trust Funds:	(dollars in thousands)
	Cost 12/31/2022													Cost 12/31/2022	Purchases	Net Proceeds(1)		Unrealized Gain(Loss)	Fair Value 12/31/2023
Equity	Equity	$	47,062	$	0	$	3,586	$	33,665	$	84,313
Debt	Debt	44,347		132,710		(126,590)		2,519		52,986
		$	91,409	$	132,710	$	(123,004)	$	36,184	$	137,299
Other
	$


	Range of Useful Life in years*	2020		2019		2018
Steam production	49-65	2.58	%	2.61	%	2.57	%
Nuclear production	37-60	1.93	%	1.94	%	1.92	%
Hydro production	50	2.00	%	2.00	%	2.00	%
Other production	25-35	2.61	%	2.61	%	2.61	%
Transmission	36	2.75	%	2.75	%	2.75	%
General	3-50	2.00-33.33%		2.00-33.33%		2.00-33.33%


	Remaining Useful Life Range in years*	2023		2022		2021
Steam production	19-21	3.05	%	13.77	%	14.47	%
Nuclear production	11-59	1.87	%	2.17	%	2.18	%
Hydro production	43	2.00	%	2.00	%	2.00	%
Other production	16-30	2.73	%	2.68	%	2.60	%
Transmission	11-59	2.75	%	2.75	%	2.75	%
General	1-42	2.00-33.33%		2.00-33.33%		2.00-33.33%


Classification
	Twelve months ended
	December 31, 2023		December 31, 2022
	(dollars in thousands)

Cash and cash equivalents	$	490,592	$	595,381
Restricted cash included in restricted cash and short-term investments	—		30,400
Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows	$	490,592	$	625,781


	Fair Value Measurements at Reporting Date Using
	December 31, 2020		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	198,325	$	198,325	$	0	$	0
International equity trust	$	120,645	0		120,645		0
Corporate bonds and debt	$	98,129	0		97,788		341
US Treasury securities	$	46,963	46,963		0		0
Mortgage backed securities	$	45,039	0		45,039		0
Domestic mutual funds	$	70,813	70,813		0		0
Municipal bonds	$	1,362	0		1,362		0
Federal agency securities	$	6,054	0		6,054		0
Other	$	10,851	7,720		3,131		0
Long-term investments:
International equity trust	$	31,378	0		31,378		0
Corporate bonds and debt	$	29,870	0		29,661		209
US Treasury securities	$	7,437	7,437		0		0
Mortgage backed securities	$	11,432	0		11,432		0
Domestic mutual funds	$	224,536	224,536		0		0
Federal agency securities	$	537	0		537		0
Treasury STRIPS	$	209,165	0		209,165		0
Other	$	3,710	3,710		0		0
Natural gas swaps	$	10,248	0		10,248		0


		Fair Value Measurements at Reporting Date Using
		December 31, 2019		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(dollars in thousands)
	Fair Value Measurements at Reporting Date Using											Fair Value Measurements at Reporting Date Using
	December 31, 2023									December 31, 2023	Quoted Prices in Active Markets for Identical Assets (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
	(dollars in thousands)											(dollars in thousands)
Nuclear decommissioning trust funds:	Nuclear decommissioning trust funds:
Domestic equity
Domestic equity
Domestic equity	Domestic equity	$	179,346	$	179,346	$	0	$	0
International equity trust	International equity trust	$	96,204	0		96,204		0
Corporate bonds and debt	Corporate bonds and debt	$	63,849	0		63,849		0
US Treasury securities	US Treasury securities	$	45,522	45,522		0		0
Mortgage backed securities	Mortgage backed securities	$	62,400	0		62,400		0
Domestic mutual funds	Domestic mutual funds	$	55,522	55,522		0		0
Municipal bonds	Municipal bonds	$	1,189	0		1,189		0
Federal agency securities	Federal agency securities	$	2,586	0		2,586		0
Non-US Gov't bonds & private placements
International mutual funds
Other	Other	$	4,721	4,450		271		0
Long-term investments:	Long-term investments:
International equity trust
International equity trust
International equity trust	International equity trust	$	23,161	0		23,161		0
Corporate bonds and debt	Corporate bonds and debt	$	20,395	0		20,395		0
US Treasury securities	US Treasury securities	$	9,257	9,257		0		0
Mortgage backed securities	Mortgage backed securities	$	12,867	0		12,867		0
Domestic mutual funds	Domestic mutual funds	$	126,380	126,380		0		0
Federal agency securities		$	1,082	0		1,082		0

Treasury STRIPS	Treasury STRIPS	$	59,816	0		59,816		0
Treasury STRIPS
Treasury STRIPS
Non-US Gov't bonds & private placements
Other	Other	$	1,906	1,906		0		0
Short-term investments: Treasury STRIPS
Natural gas swaps	Natural gas swaps	$	32,256	0		32,256		0


Year			Natural Gas Swaps (MMBTUs)
			(in millions)
2024			32.4
2025			25.1
2026			20.9
2027			10.3
2028			—
Total			88.7


	Consolidated Balance Sheet Location	Fair Value
		2023		2022
		(dollars in thousands)
Assets
Natural gas swaps	Other current assets	$	—	$	35,285
Natural gas swaps	Other deferred charges	$	25,459	$	99,725
Liabilities
Natural gas swaps	Other current liabilities	$	10,370	$	3,206
Natural gas swaps	Other deferred credits	$	1,644	$	—


	Consolidated Statement of Revenues and Expenses Location	2023		2022		2021
		(dollars in thousands)
Natural gas swaps gains	Fuel	$	2,001	$	121,626	$	31,440
Natural gas swaps losses	Fuel	(22,924)		(6,587)		(1,431)
Total		$	(20,923)	$	115,039	$	30,009


	Consolidated Balance Sheet Location
		2020		2019
		(dollars in thousands)
Natural Gas Swaps	Regulatory asset	$	10,248	$	32,256
Total		$	10,248	$	32,256


	(dollars in thousands)
	Gross Unrealized
2023	Cost		Gains		Losses		Fair Value
Equity	$	344,669	$	246,795	$	(5,549)	$	585,915
Debt	908,316		3,938		(25,181)		887,073
Other	2,889		61		(36)		2,914
Total	$	1,255,874	$	250,794	$	(30,766)	$	1,475,902


	2020				2019
	Principal		Unamortized Debt Issuance Costs and Debt Discounts		Principal		Unamortized Debt Issuance Costs and Debt Discounts
	(dollars in thousands)
FFB	$	5,985,015	$	57,971	$	5,540,215	$	60,356
FMBs	3,654,041		49,134		3,205,052		39,793
PCRBs	980,770		12,460		980,770		11,073
CFC	0		0		391		0
	$	10,619,826	$	119,565	$	9,726,428	$	111,222